Dominion Energy South Carolina (SCG) 10-K 26 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Feb. 19, 2016	Jun. 30, 2015
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, 2015
Document Fiscal Year Focus	2,015
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			$ 7,210,262,820
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, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		40,296,147

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Assets
Utility Plant In Service	$ 12,883	$ 12,289
Accumulated Depreciation and Amortization	(4,307)	(4,088)
Construction Work in Progress	4,051	3,323
Plant to be Retired, net	0	169
Nuclear Fuel, Net of Accumulated Amortization	308	329
Goodwill, Net of Writedown of $230	210	210
Utility Plant, Net	13,145	12,232
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	280	284
Assets held in trust, net-nuclear decommissioning	115	113
Other investments	71	75
Nonutility Property and Investments, Net	466	472
Current Assets:
Cash and cash equivalents	176	137
Receivables, net of allowance for uncollectible accounts	505	684
Accounts and Other Receivables, Net, Current	227	154
Inventories (at average cost):
Fuel	164	222
Materials and supplies	148	139
Prepaid Expense	115	320
Other Assets, Current	43	148
Disposal group current assets held for sale	0	341
Total Current Assets	1,378	2,145
Deferred Debits and Other Assets:
Regulatory assets	1,937	1,823
Other	220	146
Regulated Entity, Other Assets, Noncurrent	2,157	1,969
Total	17,146	16,818
Capitalization and Liabilities
Common Stock, Value, Outstanding	2,390	2,378
Retained Earnings, Unappropriated	3,118	2,684
Accumulated Other Comprehensive Income (Loss), Net of Tax	(65)	(75)
Common equity	5,443	4,987
Long-term Debt, Excluding Current Maturities	5,882	5,497
Total Capitalization	11,325	10,484
Current Liabilities:
Short-term borrowings	531	918
Long-term Debt, Current Maturities	116	166
Accounts payable	590	520
Customer deposits and customer prepayments	137	98
Taxes accrued	242	182
Interest accrued	83	83
Dividends declared	76	73
Liabilities held for sale	0	52
Derivative financial instruments	50	233
Other	127	143
Total Current Liabilities	1,952	2,468
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,907	1,931
Asset retirement obligations	520	563
Pension and other postretirement benefits	315	315
Regulatory liabilities	855	814
Other	272	243
Total Deferred Credits and Other Liabilities	3,869	3,866
Total	17,146	16,818
SCE&G
Assets
Utility Plant In Service	11,153	10,650
Accumulated Depreciation and Amortization	(3,869)	(3,667)
Construction Work in Progress	3,997	3,302
Plant to be Retired, net	0	169
Nuclear Fuel, Net of Accumulated Amortization	308	329
Utility Plant, Net	11,589	10,783
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	68	67
Assets held in trust, net-nuclear decommissioning	115	113
Other investments	1	2
Nonutility Property and Investments, Net	184	182
Current Assets:
Cash and cash equivalents	130	100
Receivables, net of allowance for uncollectible accounts	324	413
Due from Affiliate, Current	22	109
Accounts and Other Receivables, Net, Current	202	111
Inventories (at average cost):
Fuel	98	131
Materials and supplies	136	129
Prepayments	92	154
Other Assets, Current	15	99
Total Current Assets	1,019	1,246
Deferred Debits and Other Assets:
Regulatory assets	1,857	1,745
Defined Benefit Plan, Amounts Recognized in Balance Sheet	0	10
Other	116	112
Regulated Entity, Other Assets, Noncurrent	1,973	1,867
Total	14,765	14,078
Capitalization and Liabilities
Common Stock, Value, Outstanding	2,760	2,560
Retained Earnings, Unappropriated	2,265	2,077
Accumulated Other Comprehensive Income (Loss), Net of Tax	(3)	(3)
Common equity	5,022	4,634
Stockholders' Equity Attributable to Noncontrolling Interest	129	123
Total Equity	5,151	4,757
Long-term Debt, Excluding Current Maturities	4,659	4,270
Total Capitalization	9,810	9,027
Current Liabilities:
Short-term borrowings	420	709
Long-term Debt, Current Maturities	110	10
Accounts payable	469	294
Due to Affiliate, Current	113	180
Customer deposits and customer prepayments	93	61
Taxes accrued	299	170
Interest accrued	66	64
Dividends declared	75	74
Derivative financial instruments	34	208
Other	61	71
Total Current Liabilities	1,740	1,841
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,732	1,724
Asset retirement obligations	488	536
Pension and other postretirement benefits	186	195
Regulatory liabilities	635	610
Other	157	122
Due to Affiliate, Noncurrent	17	23
Total Deferred Credits and Other Liabilities	3,215	3,210
Commitments and Contingencies (Note 10)	0	0
Total	$ 14,765	$ 14,078

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) shares in Millions, $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Public Utilities, Property, Plant and Equipment, Net	$ 13,145	$ 12,232
Regulated Entity, Other Assets, Noncurrent	2,157	1,969
Nonutility property, accumulated depreciation	124	122
Receivables, net of allowance for uncollectible accounts	5	7
Assets, Current	$ 1,378	$ 2,145
Common Stock, Shares, Outstanding	142.9	142.7
SCE&G
Public Utilities, Property, Plant and Equipment, Net	$ 11,589	$ 10,783
Regulated Entity, Other Assets, Noncurrent	1,973	1,867
Receivables, net of allowance for uncollectible accounts	3	4
Assets, Current	$ 1,019	$ 1,246
Common Stock, Shares, Outstanding	40.3	40.3
VIEs | SCE&G
Public Utilities, Property, Plant and Equipment, Net	$ 700	$ 675
Regulated Entity, Other Assets, Noncurrent	53	50
Assets, Current	$ 88	$ 158

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Revenues:
Electric Domestic Regulated Revenue	$ 2,551	$ 2,622	$ 2,423
Regulated Operating Revenue, Gas	811	1,028	955
Gas-nonregulated	1,018	1,301	1,117
Regulated and Unregulated Operating Revenue	4,380	4,951	4,495
Operating Expenses [Abstract]
Fuel used in electric generation	660	793	745
Purchased power	52	81	43
Gas purchased for resale	1,287	1,729	1,491
Other operation and maintenance	715	728	708
Depreciation and amortization	358	384	378
Other taxes	234	229	220
Total Operating Expenses	3,306	3,944	3,585
Gain (Loss) On Disposition Of Regulated Business Net Of Transaction Costs	234	0	0
Operating Income	1,308	1,007	910
Other Income (Expense):
Other income	75	122	100
Other expenses	(60)	(64)	(46)
Gain (Loss) On Disposition Of Unregulated Business Net Of Transaction Costs	107	0	0
Interest charges, net of allowance for borrowed funds used during construction	(318)	(312)	(297)
Allowance for equity funds used during construction	27	33	27
Total Other Expense	(169)	(221)	(216)
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	1,139	786	694
Income Tax Expense (Benefit)	393	248	223
Income Available to Common Shareholders	$ 746	$ 538	$ 471
Per Common Share Data
Earnings Per Share, Basic	$ 5.22	$ 3.79	$ 3.40
Earnings Per Share, Diluted	$ 5.22	$ 3.79	$ 3.39
Weighted Average Common Shares Outstanding (millions)
Weighted Average Number of Shares Outstanding, Basic	142.9	141.9	138.7
Weighted Average Number of Shares Outstanding, Diluted	142.9	141.9	139.1
Dividends Declared Per Share of Common Stock (in dollars per share)	$ 2.18	$ 2.10	$ 2.03
SCE&G
Operating Revenues:
Electric Domestic Regulated Revenue	$ 2,557	$ 2,629	$ 2,431
Regulated Operating Revenue, Gas	373	462	414
Regulated Operating Revenue	2,930	3,091	2,845
Operating Expenses [Abstract]
Fuel used in electric generation	661	799	751
Purchased power	52	81	43
Gas purchased for resale	193	283	244
Other operation and maintenance	579	575	557
Depreciation and amortization	294	315	313
Other taxes	217	208	200
Total Operating Expenses	1,996	2,261	2,108
Operating Income	934	830	737
Other Income (Expense):
Other income	31	80	53
Other expenses	(31)	(34)	(18)
Interest charges, net of allowance for borrowed funds used during construction	(248)	(228)	(217)
Allowance for equity funds used during construction	25	28	25
Total Other Expense	(223)	(154)	(157)
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest	711	676	580
Income Tax Expense (Benefit)	231	218	189
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	480	458	391
Net Income (Loss) Attributable to Noncontrolling Interest	14	12	11
Earnings Available to Common Shareholder	466	446	380
Dividends Common Stock Declared	$ 285	$ 272	$ 257

CONSOLIDATED STATEMENTS OF INC5

CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Interest charges, allowance for borrowed funds used during construction	$ 15	$ 16	$ 14
SCE&G
Interest charges, allowance for borrowed funds used during construction	$ 14	$ 14	$ 13

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Available to Common Shareholders	$ 746	$ 538	$ 471
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, Net of Tax	(12)	(14)	7
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	10	11	(18)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, before Reclassification Adjustments, Net of Tax	0	(5)	7
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Net of Tax	0	1	1
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	0	(4)	8
Other Comprehensive Income (Loss), Net of Tax	10	(15)	26
Other Comprehensive Income (Loss)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax	0	1	1
Net Income (Loss) Attributable to Parent [Abstract]
Total Comprehensive Income (Loss)	756	523	497
SCE&G
Other Comprehensive Income (Loss), Net of Tax	0	0	1
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	480	458	391
Other Comprehensive Income (Loss)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax	0	0	1
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax	0	0	0
Net Income (Loss) Attributable to Parent [Abstract]
Total Comprehensive Income (Loss)	480	458	392
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	480	458	392
Genco
Other Comprehensive Income (Loss)
Less comprehensive income attributable to noncontrolling interest	14	12	11
SCEG excluding VIEs [Member]
Income Available to Common Shareholders	466	446	380
Net Income (Loss) Attributable to Parent [Abstract]
Total Comprehensive Income (Loss)	466	446	381
Interest Rate Contract
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	7	7	8
Commodity Contract [Member]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 15	$ (4)	$ 3

CONSOLIDATED STATEMENTS OF COM7

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	$ (7)	$ (9)	$ 4
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax	4	4	5
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income, Tax	9	(2)	2
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Tax	$ 0	$ (3)	$ 4

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash Flows from Operating Activities
Net Income (Loss) Available to Common Stockholders, Basic	$ 746	$ 538	$ 471
Adjustments to reconcile net income to net cash provided from operating activities:
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal	355
Income (Loss) from Equity Method Investments, Net of Dividends or Distributions	(3)	(5)	(7)
Deferred income taxes, net	(31)	235	49
Depreciation and amortization	368	403	393
Amortization of nuclear fuel	46	45	57
Allowance for equity funds used during construction	(27)	(33)	(27)
Carrying cost recovery	(12)	(9)	(3)
Cash provided (used) by changes in certain assets and liabilities:
Increase (Decrease) in Receivables	(188)	33	38
Increase (Decrease) in Inventories	16	62	(21)
Increase (Decrease) in Prepaid Expense	(211)	235	(49)
Increase (Decrease) in Other Regulatory Assets	(148)	372	(113)
Increase (Decrease) in Regulatory liabilities	3	(133)	56
Increase (Decrease) in Accounts Payable	(78)	36	24
Increase (Decrease) in Taxes accrued	61	(24)	42
Increase (Decrease) in Pension and Postretirement Obligations	(6)	133	(217)
Increase (Decrease) in Derivative Assets and Liabilities	(183)	225	(72)
Changes in other assets	21	8	(17)
Changes in other liabilities	14	19	108
Net Cash Provided from Operating Activities	1,059	730	1,050
Cash Flows From Investing Activities
Property additions and construction expenditures	(1,153)	(1,092)	(1,106)
Proceeds from Sale of Property, Plant, and Equipment	647
Proceeds from investments (including derivative collateral posted)	1,117	347	222
Purchase of investments (including derivative collateral posted)	(1,018)	(475)	(176)
Payments upon interest rate contract settlement	(263)	(95)	(49)
Payments for (Proceeds from) Hedge, Investing Activities	10	0	163
Net Cash Used for Investing Activities	(660)	(1,315)	(946)
Cash Flows from Financing Activities
Proceeds from Issuance of Common Stock	14	98	295
Proceeds from issuance of long-term debt	491	294	451
Repayments of Long-term Debt	(166)	(54)	(258)
Dividends	(309)	(294)	(281)
Short-term borrowings, net	(387)	542	(247)
Proceeds from (Payments for) Other Financing Activities	(3)
Net Cash Provided From Financing Activities	(360)	586	(40)
Net (Decrease) Increase in Cash and Cash Equivalents	39	1	64
Cash and Cash Equivalents, January 1	137	136	72
Cash and Cash Equivalents, December 31	176	137	136
Supplemental Cash Flow Information
Cash paid for-Interest (net of capitalized interest )	306	301	288
Cash paid for-Income taxes	184	299	104
Cash Flow, Noncash Investing and Financing Activities Disclosure
Accrued construction expenditures	244	180	111
Capital Lease Obligations Incurred	6	5	6
Noncash or Part Noncash Acquisition, Fixed Assets Acquired			98
SCE&G
Cash Flows from Operating Activities
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	480	458	391
Adjustments to reconcile net income to net cash provided from operating activities:
Income (Loss) from Equity Method Investments	(4)	(5)	(3)
Deferred income taxes, net	8	187	29
Depreciation and amortization	294	318	315
Amortization of nuclear fuel	46	45	57
Allowance for equity funds used during construction	(25)	(28)	(25)
Carrying cost recovery	(12)	(9)	(3)
Cash provided (used) by changes in certain assets and liabilities:
Increase (Decrease) in Receivables	(85)	(51)	53
Increase (Decrease) in Due from Affiliates, Current	(16)	90	(17)
Increase (Decrease) in Inventories	24	52	(35)
Increase (Decrease) in Prepaid Expense	(70)	89	(8)
Increase (Decrease) in Other Regulatory Assets	(150)	350	(83)
Increase (Decrease) in Regulatory liabilities	1	(132)	54
Increase (Decrease) in Accounts Payable	11	(49)	12
Increase (Decrease) in Due to Affiliates, Current	(17)	63	(7)
Increase (Decrease) in Taxes accrued	129	(53)	72
Increase (Decrease) in Pension and Postretirement Obligations	(5)	106	(186)
Increase (Decrease) in Derivative Assets and Liabilities	(174)	207	(65)
Changes in other assets	(38)	(12)	(27)
Changes in other liabilities	9	50	146
Increase (Decrease) in Due to Affiliates	(6)	(9)	(58)
Net Cash Provided from Operating Activities	1,078	641	852
Cash Flows From Investing Activities
Property additions and construction expenditures	(1,008)	(934)	(1,003)
Proceeds from investments (including derivative collateral posted)	975	275	144
Purchase of investments (including derivative collateral posted)	(887)	(381)	(116)
Payments upon interest rate contract settlement	(263)	(95)	(49)
Payments for (Proceeds from) Hedge, Investing Activities	10	0	163
Proceeds from Investment In Affiliate	71
Investment In Affiliate		(80)	0
Net Cash Used for Investing Activities	(1,102)	(1,215)	(861)
Cash Flows from Financing Activities
Proceeds from issuance of long-term debt	491	294	451
Repayments of Long-term Debt	(11)	(48)	(251)
Dividends	(285)	(260)	(241)
Short-term borrowings, net	(289)	458	(198)
Short-term borrowings-affiliate,net	(50)	56	(22)
Contributions from parent	204	89	314
Payment to Parent representing the return of Contribution Proceeds	(4)	(7)	(3)
Proceeds from (Payments for) Other Financing Activities	(2)
Net Cash Provided From Financing Activities	54	582	50
Net (Decrease) Increase in Cash and Cash Equivalents	30	8	41
Cash and Cash Equivalents, January 1	100	92	51
Cash and Cash Equivalents, December 31	130	100	92
Supplemental Cash Flow Information
Cash paid for-Interest (net of capitalized interest )	228	210	200
Cash paid for-Income taxes	89	177	92
Proceeds from Income Tax Refunds	84
Cash Flow, Noncash Investing and Financing Activities Disclosure
Accrued construction expenditures	230	151	100
Capital Lease Obligations Incurred	$ 6	$ 5	4
Noncash or Part Noncash Acquisition, Fixed Assets Acquired			$ 98

CONSOLIDATED STATEMENTS OF CAS9

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parentheticals) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash paid for interest, capitalized interest	$ 15	$ 16	$ 14
SCE&G
Cash paid for interest, capitalized interest	$ 14	$ 14	$ 13

CONSOLIDATED STATEMENTS OF COMM

CONSOLIDATED STATEMENTS OF COMMON EQUITY - USD ($) shares in Millions	Total	AOCI Attributable to Parent [Member]	Reclassification out of Accumulated Other Comprehensive Income [Member]	Genco	SCE&G	SCEG excluding VIEs [Member]
Common Stock, Value, Outstanding						$ 2,167,000,000
Stockholders' Equity Attributable to Noncontrolling Interest				$ 114,000,000
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest					$ 4,043,000,000
Stockholders' Equity Attributable to Parent at Dec. 31, 2012	$ 4,154,000,000
Shares, Outstanding at Dec. 31, 2012	132					40
Stockholders' Equity before Treasury Stock at Dec. 31, 2012	$ 1,992,000,000
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax at Dec. 31, 2012	(70,000,000)
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax at Dec. 31, 2012	(16,000,000)
Retained Earnings, Unappropriated at Dec. 31, 2012	2,257,000,000					$ 1,766,000,000
Treasury Stock, Value at Dec. 31, 2012	(9,000,000)
Accumulated Other Comprehensive Income (Loss) at Dec. 31, 2012	$ (86,000,000)					(4,000,000)
Stock Issued During Period, Shares, New Issues	9
Stock Issued During Period, Value, Other	$ 297,000,000
Common stock issued	297,000,000
Dividends, Common Stock	(284,000,000)
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	18,000,000
Net Income (Loss) Attributable to Noncontrolling Interest				11,000,000	11,000,000
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest					391,000,000
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax, Portion Attributable to Parent					1,000,000	1,000,000
Contributions from parent				1,000,000	314,000,000
Dividends					(257,000,000)	(250,000,000)
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders				(7,000,000)
Other Comprehensive Income (Loss), Net of Tax	26,000,000				1,000,000
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	(7,000,000)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax	7,000,000
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	11,000,000
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Reclassified During Period, Net of Tax	1,000,000				1,000,000
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	497,000,000				392,000,000	381,000,000
Proceeds from Contribution from Parent, net of return of Proceeds					311,000,000	312,000,000
Income Available to Common Shareholders	$ 471,000,000					$ 380,000,000
Dividends Declared Per Share of Common Stock (in dollars per share)	$ 2.03
Shares, Outstanding at Dec. 31, 2013	141					40
Stockholders' Equity before Treasury Stock at Dec. 31, 2013	$ 2,289,000,000
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax at Dec. 31, 2013	(52,000,000)
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax at Dec. 31, 2013	(8,000,000)
Retained Earnings, Unappropriated at Dec. 31, 2013	2,444,000,000					$ 1,896,000,000
Treasury Stock, Value at Dec. 31, 2013	(9,000,000)
Accumulated Other Comprehensive Income (Loss) at Dec. 31, 2013	(60,000,000)					(3,000,000)
Stockholders' Equity Attributable to Parent at Dec. 31, 2013	$ 4,664,000,000
Common Stock, Value, Outstanding						2,479,000,000
Stockholders' Equity Attributable to Noncontrolling Interest				117,000,000
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest					4,489,000,000
AOCI before Tax, Attributable to Parent		$ 14,000,000	$ (12,000,000)
Stock Issued During Period, Shares, New Issues	2
Stock Issued During Period, Value, Other	$ 99,000,000
Stock Repurchased During Period, Value	1,000,000
Common stock issued	98,000,000
Dividends, Common Stock	(298,000,000)
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	(11,000,000)
Net Income (Loss) Attributable to Noncontrolling Interest				12,000,000	12,000,000
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest					458,000,000
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax, Portion Attributable to Parent					0	0
Contributions from parent				1,000,000	89,000,000
Dividends					(272,000,000)	(265,000,000)
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders				(7,000,000)
Other Comprehensive Income (Loss), Net of Tax	(15,000,000)				0
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	(14,000,000)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax	(5,000,000)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	3,000,000
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Reclassified During Period, Net of Tax	1,000,000				0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	523,000,000				458,000,000	446,000,000
Proceeds from Contribution from Parent, net of return of Proceeds					82,000,000	81,000,000
Income Available to Common Shareholders	$ 538,000,000					$ 446,000,000
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	$ 2,388,000,000
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax at Dec. 31, 2014	(63,000,000)
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax at Dec. 31, 2014	(12,000,000)
Retained Earnings, Unappropriated at Dec. 31, 2014	2,684,000,000				2,077,000,000	$ 2,077,000,000
Treasury Stock, Value at Dec. 31, 2014	(10,000,000)
Accumulated Other Comprehensive Income (Loss) at Dec. 31, 2014	(75,000,000)					(3,000,000)
Stockholders' Equity Attributable to Parent at Dec. 31, 2014	4,987,000,000				4,634,000,000
Common Stock, Value, Outstanding	$ 2,378,000,000				2,560,000,000	2,560,000,000
Stockholders' Equity Attributable to Noncontrolling Interest				123,000,000	123,000,000
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest					4,757,000,000
AOCI before Tax, Attributable to Parent		(19,000,000)	(4,000,000)
Stock Issued During Period, Shares, New Issues	0
Stock Issued During Period, Value, Other	$ 14,000,000
Stock Repurchased During Period, Value	2,000,000
Common stock issued	12,000,000
Dividends, Common Stock	(312,000,000)
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	10,000,000
Net Income (Loss) Attributable to Noncontrolling Interest				14,000,000	14,000,000
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest					480,000,000
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax, Portion Attributable to Parent					0	0
Contributions from parent				0	204,000,000
Dividends					(286,000,000)	(278,000,000)
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders				(8,000,000)
Other Comprehensive Income (Loss), Net of Tax	10,000,000				0
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	(12,000,000)
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	22,000,000
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	756,000,000				480,000,000	466,000,000
Proceeds from Contribution from Parent, net of return of Proceeds						200,000,000
Income Available to Common Shareholders	$ 746,000,000					$ 466,000,000
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	$ 2,402,000,000
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax at Dec. 31, 2015	(53,000,000)
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax at Dec. 31, 2015	(12,000,000)
Retained Earnings, Unappropriated at Dec. 31, 2015	3,118,000,000				2,265,000,000	$ 2,265,000,000
Treasury Stock, Value at Dec. 31, 2015	(12,000,000)
Accumulated Other Comprehensive Income (Loss) at Dec. 31, 2015	(65,000,000)					(3,000,000)
Stockholders' Equity Attributable to Parent at Dec. 31, 2015	5,443,000,000				5,022,000,000
Common Stock, Value, Outstanding	$ 2,390,000,000				2,760,000,000	$ 2,760,000,000
Stockholders' Equity Attributable to Noncontrolling Interest				$ 129,000,000	129,000,000
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest					$ 5,151,000,000
AOCI before Tax, Attributable to Parent		$ (12,000,000)	$ (22,000,000)

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2015
Significant Accounting Policies
Significant Accounting Policies [Text Block]	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Organization and Principles of Consolidation 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. CGT and SCI were sold in the first quarter of 2015. Accordingly, the assets and liabilities of these entities are aggregated and shown as Assets held for sale and Liabilities held for sale in the December 31, 2014 consolidated balance sheet. See Note 13. The Company 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. 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 In April 2015, the FASB issued accounting guidance intended to simplify the presentation of debt issuance costs by requiring that such costs be deducted from carrying amounts related to debt when presented in the balance sheet. As permitted, the Company adopted this guidance retrospectively in the fourth quarter of 2015. As a result, for 2014 $34 million of unamortized debt issuance costs were reclassified to long-term debt, and certain amounts in Note 4 and Note 12 were also reclassified for comparative periods. The effect of adoption on the Company’s results of operations and cash flows was not significant. In November 2015, the FASB issued accounting guidance intended to simplify the presentation of deferred tax assets and deferred tax liabilities by netting and classifying them as noncurrent on the statement of financial position. As permitted, the Company early adopted this guidance retrospectively in the fourth quarter of 2015. As a result, for 2014 $65.5 million of net deferred tax liabilities previously classified in current liabilities were reclassified to long-term liabilities. The effect of adoption on the Company's results of operations and cash flows was not significant. 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 6.1% for 2015, 7.2% for 2014 and 6.9% for 2013. 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. The Company records provisions for depreciation and amortization 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 Note 13) 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: 2015 2014 2013 SCE&G 2.55 % 2.85 % 2.96 % GENCO 2.66 % 2.66 % 2.66 % CGT — 2.11 % 2.19 % PSNC Energy 2.94 % 2.98 % 3.01 % Weighted average of above 2.61 % 2.84 % 2.93 % 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 Summer Station 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, 2015 2014 Unit 1 New Units Unit 1 New Units Percent owned 66.7% 55.0% 66.7% 55.0% Plant in service $ 1.2 billion — $ 1.2 billion — Accumulated depreciation $ 620.4 million — $ 578.3 million — Construction work in progress $ 214.6 million $ 3.4 billion $ 199.3 million $ 2.7 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 Summer Station Unit 1 and the New Units. These amounts totaled $178.8 million at December 31, 2015 and $88.9 million at December 31, 2014. Plant to be Retired At December 31, 2014, SCE&G expected to retire three units that are or were coal-fired by 2020, which was prior to the end of the previously estimated useful lives over which the units were being depreciated. As such, these units were identified as Plant to be Retired. Subsequently, these units were converted to be gas-fired. In the third quarter of 2015, in connection with the adoption of a customary depreciation study and related analysis (see Note 2), SCE&G determined that these units would not likely be retired by 2020, and their depreciation rates were set to recover the units' net carrying value over their respective revised useful lives. Accordingly, the net carrying value of these units is no longer classified as Plant to be Retired 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. Through 2017, 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, 2015 and 2014, SCE&G incurred $16.5 million and $19.4 million , respectively, for turbine maintenance. Nuclear refueling outages are scheduled 18 months apart. As approved by the SCPSC, effective January 1, 2013, SCE&G accrues $1.4 million per month for its portion of the nuclear refueling outages that are scheduled for the spring of 2014 through the spring of 2020. Total costs for 2014 were $43.7 million , of which SCE&G was responsible for $29.1 million . Total costs for 2015 were $40.2 million , of which SCE&G was responsible for $26.8 million . Goodwill The Company considers certain amounts categorized by FERC as “acquisition adjustments” to be goodwill. For each period presented, assets with a carrying value of $210 million (net of a writedown taken in 2002 of $230 million ) for PSNC Energy (Gas Distribution segment) were classified as goodwill. The Company tests goodwill for impairment annually as of January 1, unless indicators, events or circumstances require interim testing to be performed. The goodwill impairment testing is generally a two-step quantitative process which in 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. Accounting guidance adopted by the Company gives it the option to first perform a qualitative assessment of impairment. Based on this qualitative ("step zero") 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 the two-step quantitative assessment. In evaluations of PSNC Energy, fair value was estimated using the assistance of an independent appraisal. In evaluations for the periods presented, step one has indicated no impairment, and no impairment charges have been recorded. Should a write-down be required in the future, such a charge would be treated as an operating expense. Nuclear Decommissioning Based on a decommissioning cost study, SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Summer Station Unit 1, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $696.8 million , stated in 2012 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Summer Station 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, amounts collected through rates ( $3.2 million pre-tax in each period presented) are invested in insurance policies on the lives of certain Company personnel. SCE&G transfers to an external trust fund the amounts collected through electric rates, insurance proceeds and interest thereon, less expenses. 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 Summer Station Unit 1 on an after-tax basis. Cash and Cash Equivalents The Company considers temporary cash investments having original maturities of three months or less at time of purchase 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. Asset Management and Supply Service Agreements PSNC Energy utilizes asset management and supply service agreements with counterparties for certain natural gas storage facilities. Such counterparties held 46% and 48% of PSNC Energy’s natural gas inventory at December 31, 2015 and December 31, 2014, respectively, with a carrying value of $17.7 million and $26.1 million , respectively, through either capacity release or agency relationships. Under the terms of the asset management agreements, PSNC Energy receives storage asset management fees. No fees are received under supply service agreements. The agreements expire March 31, 2017. Income Taxes The Company 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. Regulatory Assets and Regulatory Liabilities The Company’s rate-regulated utilities record costs that have been or are expected to be allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense or record revenue in a period different from the period in which the revenue would be recorded by a nonregulated enterprise. These expenses deferred for future recovery from customers or obligations to be refunded 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 or accounts payable, respectively. Debt Issuance Premiums, Discounts and Other Costs The Company presents long-term debt premiums, discounts and debt issuance costs within long-term debt and amortizes them 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 The Company maintains an environmental assessment program 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 The Company presents the revenues and expenses of its regulated businesses and its retail natural gas marketing businesses (including those activities of segments described in Note 12) within operating income, and it presents all other activities within other income (expense). Consistent with this presentation, the gain on the sale of CGT is reflected within operating income and the gain on the sale of SCI is reflected within other income (expense). Revenue Recognition The Company records revenues during the accounting period in which it provides services to customers and includes estimated amounts for electricity and natural gas delivered but not billed. Unbilled revenues totaled $129.1 million at December 31, 2015 and $186.4 million at December 31, 2014. 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. An eWNA for SCE&G's electric customers was discontinued effective with the first billing cycle of 2014 as approved by the SCPSC. 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 that are 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 The Company computes basic earnings per share by dividing net income by the weighted average number of common shares outstanding for the period. The Company computes diluted earnings per share using this same formula, after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method. The weighted average number of common shares for each period presented for basic and diluted earnings per share purposes were identical, except that for 2013, the net effect of equity forward contracts resulted in such shares for diluted earnings per share purposes being 0.4 million higher than for basic earnings per share purposes. New Accounting Matters In April 2014, the FASB issued accounting guidance for reporting discontinued operations and disclosures of disposals of components of an entity. Under this guidance, only those discontinued operations which represent a strategic shift that will have a major effect on an entity’s operations and financial results should be reported as discontinued operations in the financial statements. As permitted, the Company adopted this guidance for the period ended December 31, 2014. In May 2014, the FASB issued accounting guidance for revenue arising from contracts with customers that supersedes most current revenue recognition guidance, including industry-specific guidance. This 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 is required to adopt this guidance in the first quarter of 2018 and early adoption is permitted in the first quarter of 2017. Adoption using a retrospective method is required, with options to elect certain practical expedients or to recognize a cumulative effect in the year of initial adoption. The Company has not determined when it will adopt this guidance or what elections it will make. The Company has not determined the impact this guidance will have on its results of operations, cash flows or financial position. In April 2015, the FASB issued accounting guidance related to fees paid by a customer in a cloud computing arrangement. Among other things, the guidance clarifies how to account for a software license element included in a cloud computing arrangement, and makes explicit that a cloud computing arrangement not containing a software license element should be accounted for as a service contract. The Company has determined that this guidance, when adopted in the first quarter of 2016, will not significantly impact the Company’s results of operations, cash flows or financial position. In July 2015, the FASB issued accounting guidance intended to simplify the subsequent measurement of inventory cost by requiring most inventory to be measured at the lower of cost and net realizable value. The Company expects to adopt this guidance when required in the first quarter of 2017. The Company is evaluating this guidance and has not determined what impact it will have on its results of operations, cash flows or financial position. In January 2016, the FASB issued accounting guidance intended to clarify the classification and measurement of financial instruments and financial liabilities, among other things. The Company expects to adopt this guidance when required in the first quarter of 2018. The Company is evaluating this guidance and has not determined what impact it will have on its results of operations, cash flows or financial position. 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 twelve 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 of 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 has not determined what impact this guidance will have on its results of operations, cash flows or financial position.
SCE&G
Significant Accounting Policies
Significant Accounting Policies [Text Block]	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Organization and Principles of Consolidation 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, the accompanying 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. Accordingly, 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 megawatt 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 $491 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 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 In April 2015, the FASB issued accounting guidance intended to simplify the presentation of debt issuance costs by requiring that such costs be deducted from carrying amounts related to debt when presented in the balance sheet. As permitted, Consolidated SCE&G adopted this guidance retrospectively in the fourth quarter of 2015. As a result, for 2014 $29 million of unamortized debt issuance costs were reclassified to long-term debt, and certain amounts in Note 4 and Note 12 were also reclassified for comparative periods. The effect of adoption on Consolidated SCE&G’s results of operations and cash flows was not significant. In November 2015, the FASB issued accounting guidance intended to simplify the presentation of deferred tax assets and deferred tax liabilities by netting and classifying them as noncurrent on the statement of financial position. As permitted, Consolidated SCE&G early adopted this guidance retrospectively in the fourth quarter of 2015. As a result, for 2014 $27.9 million of net deferred tax liabilities previously classified in current liabilities were reclassified to long-term liabilities. The effect of adoption on Consolidated SCE&G's results of operations and cash flows was not significant. 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. Consolidated SCE&G calculated AFC using average composite rates of 5.6% for 2015, 6.5% for 2014 and 6.9% for 2013. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561. SCE&G capitalizes interest on nuclear fuel in process at the actual interest cost incurred. Consolidated SCE&G records provisions for depreciation and amortization 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. The composite weighted average depreciation rates for utility plant assets were 2.56% in 2015, 2.84% in 2014 and 2.94% in 2013. 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 Summer Station 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, 2015 2014 Unit 1 New Units Unit 1 New Units Percent owned 66.7% 55.0% 66.7% 55.0% Plant in service $ 1.2 billion — $ 1.2 billion — Accumulated depreciation $ 620.4 million — $ 578.3 million — Construction work in progress $ 214.6 million $ 3.4 billion $ 199.3 million $ 2.7 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 Summer Station Unit 1 and the New Units. These amounts totaled $178.8 million at December 31, 2015 and $88.9 million at December 31, 2014. Plant to be Retired At December 31, 2014, SCE&G expected to retire three units that are or were coal-fired by 2020, which was prior to the end of the previously estimated useful lives over which the units were being depreciated. As such, these units were identified as Plant to be Retired. Subsequently, these units were converted to be gas-fired. In the third quarter of 2015, in connection with the adoption of a customary depreciation study and related analysis (see Note 2), SCE&G determined that these units would not likely be retired by 2020, and their depreciation rates were set to recover the units' net carrying value over their respective revised useful lives. Accordingly, the net carrying value of these units is no longer classified as Plant to be Retired 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 are classified as a regulatory asset or regulatory liability on the consolidated balance sheet. Other planned major maintenance is expensed when incurred. Through 2017, 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, 2015 and 2014, SCE&G incurred $16.5 million and $19.4 million , respectively, for turbine maintenance. Nuclear refueling outages are scheduled 18 months apart. As approved by the SCPSC, effective January 1, 2013, SCE&G accrues $1.4 million per month for its portion of the nuclear refueling outages that are scheduled for the spring of 2014 throught the spring of 2020. Total costs for 2014 were $43.7 million , of which SCE&G was responsible for $29.1 million . Total costs for 2015 were $40.2 million , of which SCE&G was responsible for $26.8 million . Nuclear Decommissioning Based on a decommissioning cost study, SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Summer Station Unit 1, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $696.8 million , stated in 2012 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Summer Station 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, amounts collected through rates ( $3.2 million pre-tax in each period presented) are invested in insurance policies on the lives of certain SCE&G and affiliate personnel. SCE&G transfers to an external trust fund the amounts collected through electric rates, insurance proceeds and interest thereon, less expenses. 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 Summer Station Unit 1 on an after-tax basis. Cash and Cash Equivalents Consolidated SCE&G considers temporary cash investments having original maturities of three months or less at time of purchase 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. Income Taxes Consolidated SCE&G is included in the consolidated federal income tax returns of SCANA. Under a joint consolidated income tax allocation agreement, each SCANA 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; otherwise, they are charged or credited to income tax expense. 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 Consolidated SCE&G records costs that have been or are expected to be allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense or record revenue in a period different from the period in which the revenue would be recorded by a nonregulated enterprise. These expenses deferred for future recovery from customers or obligations to be refunded 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 or accounts payable, respectively. Debt Issuance Premiums, Discounts and Other Costs Consolidated SCE&G presents long-term debt premiums, discounts and debt issuance costs within long-term debt and amortizes them as components of interest charges over the terms of the respective debt issues. 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 SCE&G maintains an environmental assessment program 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 Consolidated SCE&G presents the revenues and expenses of its regulated activities (including those activities of segments described in Note 12) within operating income, and it presents all other activities within other income (expense). Revenue Recognition Consolidated SCE&G records revenues during the accounting period in which it provides services to customers and includes estimated amounts for electricity and natural gas delivered but not billed. Unbilled revenues totaled $101.5 million at December 31, 2015 and $115.8 million at December 31, 2014. 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. Customers subject to the 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. 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. An eWNA for SCE&G's electric customers was discontinued effective with the first billing cycle of 2014 as approved by the SCPSC. Taxes that are 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 In May 2014, the FASB issued accounting guidance for revenue arising from contracts with customers that supersedes most current revenue recognition guidance, including industry-specific guidance. This 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. Consolidated SCE&G is required to adopt this guidance in the first quarter of 2018 and early adoption is permitted in the first quarter of 2017. Adoption using a retrospective method is required, with options to elect certain practical expedients or to recognize a cumulative effect in the year of initial adoption. Consolidated SCE&G has not determined when it will adopt this guidance or what elections it will make. Consolidated SCE&G has not determined the impact this guidance will have on its results of operations, cash flows or financial position. In April 2015, the FASB issued accounting guidance related to fees paid by a customer in a cloud computing arrangement. Among other things, the guidance clarifies how to account for a software license element included in a cloud computing arrangement, and makes explicit that a cloud computing arrangement not containing a software license element should be accounted for as a service contract. Consolidated SCE&G has determined that this guidance, when adopted in the first quarter of 2016, will not significantly impact Consolidated SCE&G’s results of operations, cash flows or financial position. In July 2015, the FASB issued accounting guidance intended to simplify the subsequent measurement of inventory cost by requiring most inventory to be measured at the lower of cost and net realizable value. Consolidated SCE&G expects to adopt this guidance when required in the first quarter of 2017. Consolidated SCE&G is evaluating this guidance and has not determined what impact it will have on its results of operations, cash flows or financial position. In January 2016, the FASB issued accounting guidance intended to clarify the classification and measurement of financial instruments and financial liabilities, among other things. Consolidated SCE&G expects to adopt this guidance when required in the first quarter of 2018. Consolidated SCE&G is evaluating this guidance and has not determined what impact it will have on its results of operations, cash flows or financial position. 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 twelve 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 of 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 year beginning in 2019. Consolidated SCE&G has not determined what impact this guidance will have on its results of operations, cash flows or financial position.

RATE AND OTHER REGULATORY MATTE

RATE AND OTHER REGULATORY MATTERS	12 Months Ended
	Dec. 31, 2015
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 a November 2013 SCPSC accounting order, the Company's electric revenue for 2013 was reduced for adjustments to the fuel cost component and related under-collected fuel balance of $41.6 million . Such adjustments are fully offset by the recognition within other income, also pursuant to that accounting order, of gains realized upon the 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. See also Note 6. 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 are 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 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. SCE&G is to make a good faith effort to have at least 30 MW of utility-scale solar capacity in service by the end of 2016. 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, the Company's net income for 2015 increased approximately $9.8 million as a result of this change in estimate. In October 2015, the SCPSC initiated its 2016 annual review of base rates for fuel costs. A public hearing for this annual review is scheduled for April 7, 2016. Electric - Base Rates Prior to 2014, certain of SCE&G's electric rates included an adjustment for eWNA. The eWNA was designed to mitigate the effects of abnormal weather on residential and commercial customers' bills. On November 26, 2013, SCE&G, ORS and certain other parties filed a joint petition with the SCPSC requesting, among other things, that the SCPSC discontinue the eWNA effective with bills rendered on or after the first billing cycle of January 2014. On December 20, 2013, the SCPSC granted the relief requested in the joint petition. In connection with the termination of the eWNA effective December 31, 2013, and pursuant to an SCPSC order, electric revenues were reduced to reverse the prior accrual of an under-collected balance of $8.5 million . This revenue reduction was fully offset by the recognition within other income of $8.5 million of gains realized upon the settlement of certain interest rate derivatives, which gains had been deferred as a regulatory liability. Pursuant to an SCPSC order, SCE&G removes from rate base 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 $9.5 million and $5.8 million during 2015 and 2014, 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 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 2015 First billing cycle of May $32.0 million 2014 First billing cycle of May $15.4 million 2013 First billing cycle of May $16.9 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. In January 2016, SCE&G submitted its annual DSM Programs filing to the SCPSC. If approved, the filing would allow recovery of $37.6 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. Through 2015, requested rate adjustments have been based on SCE&G's updated cost of debt and capital structure and on an allowed return on common equity of 11.0%. The SCPSC has approved recovery of the following amounts under the BLRA effective for bills rendered on and after October 30 in the following years: Year Increase Amount 2015 2.6% $64.5 million 2014 2.8% $66.2 million 2013 2.9% $67.2 million In September 2015, the SCPSC approved a revision to the allowed return on equity for new nuclear construction from 11.0% to 10.5% . This revised return on equity will be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2016, until such time as the New Units are completed. See Note 10. 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 2015 No change — 2014 0.6 % Decrease $2.6 million 2013 No change — SCE&G's natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred, including transportation costs. SCE&G's gas rates are calculated using a methodology which may adjust the cost of gas monthly based on a 12-month rolling average, and its gas purchasing policies and practices are reviewed annually by the SCPSC. The annual reviews conducted for each of the 12-month periods ended July 31, 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. In October 2015, in connection with PSNC Energy's 2015 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, 2015. In May 2014, the NCUC issued an order requiring utilities to adjust rates to reflect changes in the state corporate income tax rate that had been enacted by the North Carolina legislature and to file a proposal to refund amounts previously collected on a provisional basis. Pursuant to the order, PSNC Energy lowered its rates effective July 1, 2014, and refunded the amounts previously collected through the normal operation of its Rider D rate mechanism. These amounts were not significant for any period presented. Regulatory Assets and Regulatory Liabilities The Company's cost-based, rate-regulated utilities recognize in their financial statements certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, the Company has 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. December 31, Millions of dollars 2015 2014 Regulatory Assets: Accumulated deferred income taxes $ 298 $ 284 AROs and related funding 405 366 Deferred employee benefit plan costs 325 350 Deferred losses on interest rate derivatives 535 453 Unrecovered plant 127 137 Environmental remediation costs 42 40 DSM Programs 61 56 Other 144 137 Total Regulatory Assets $ 1,937 $ 1,823 Regulatory Liabilities: Asset removal costs $ 732 $ 703 Deferred gains on interest rate derivatives 96 82 Other 27 29 Total Regulatory Liabilities $ 855 $ 814 Accumulated deferred income tax liabilities that arose from utility operations that have not been included in customer rates are recorded as a regulatory asset. Substantially all of these regulatory assets relate to AFC and are expected to be recovered over the remaining lives of the related property which may range up to approximately 85 years. ARO 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. Accordingly, 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 12 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 will amortize 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 the Company, and are expected to be recovered over periods of up to approximately 24 years. DSM Programs represent deferred costs associated with such programs. As a result of the April 2015 SCPSC order, deferred costs are currently being recovered over approximately five years through an approved rate rider. Various other regulatory assets are expected to be recovered in rates over periods of up to approximately 30 years. 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 received by the Company. 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 could be required to write off its regulatory assets and liabilities. Such an event could have a material effect on the Company's results of operations, liquidity or financial position 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 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 a November 2013 SCPSC accounting order, SCE&G's electric revenue for 2013 was reduced for adjustments to the fuel cost component and related under-collected fuel balance of $41.6 million . Such adjustments are fully offset by the recognition within other income, also pursuant to that accounting order, of gains realized upon the 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. See also Note 6. 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 are 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 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. SCE&G is to make a good faith effort to have at least 30 MW of utility-scale solar capacity in service by the end of 2016. 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 in 2015, and pursuant to the SCPSC order, SCE&G reduced its electric operating revenues by approximately $14.5 million 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. In October 2015, the SCPSC initiated its 2016 annual review of base rates for fuel costs. A public hearing for this annual review is scheduled for April 7, 2016. Electric - Base Rates Prior to 2014, certain of SCE&G's electric rates included an adjustment for eWNA. The eWNA was designed to mitigate the effects of abnormal weather on residential and commercial customers' bills. On November 26, 2013, SCE&G, ORS and certain other parties filed a joint petition with the SCPSC requesting, among other things, that the SCPSC discontinue the eWNA effective with bills rendered on or after the first billing cycle of January 2014. On December 20, 2013, the SCPSC granted the relief requested in the joint petition. In connection with the termination of the eWNA effective December 31, 2013, and pursuant to an SCPSC order, electric revenues were reduced to reverse the prior accrual of an under-collected balance of $8.5 million . This revenue reduction was fully offset by the recognition within other income of $8.5 million of gains realized upon the settlement of certain interest rate derivatives, which gains had been deferred as a regulatory liability. Pursuant to an SCPSC order, SCE&G removes from rate base 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 $9.5 million and $5.8 million during 2015 and 2014, 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 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 2015 First billing cycle of May $32.0 million 2014 First billing cycle of May $15.4 million 2013 First billing cycle of May $16.9 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. In January 2016, SCE&G submitted its annual DSM Programs filing to the SCPSC. If approved, the filing would allow recovery of $37.6 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. Through 2015, requested rate adjustments have been based on SCE&G's updated cost of debt and capital structure and on an allowed return on common equity of 11.0%. The SCPSC has approved recovery of the following amounts under the BLRA effective for bills rendered on and after October 30 in the following years: Year Increase Amount 2015 2.6% $64.5 million 2014 2.8% $66.2 million 2013 2.9% $67.2 million In September 2015, the SCPSC approved a revision to the allowed return on equity for new nuclear construction from 11.0% to 10.5% . This revised return on equity will be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2016, until such time as the New Units are completed. See Note 10. Gas 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 2015 No change — 2014 0.6 % Decrease $ 2.6 million 2013 No change — SCE&G's natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred, including transportation costs. SCE&G's gas rates are calculated using a methodology which may adjust the cost of gas monthly based on a 12-month rolling average, and its gas purchasing policies and practices are reviewed annually by the SCPSC. The annual reviews conducted for each of the 12-month periods ended July 31, 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. Regulatory Assets and Regulatory Liabilities Consolidated SCE&G has significant cost-based, rate-regulated operations and recognizes in its financial statements certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, Consolidated SCE&G has 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. December 31, Millions of dollars 2015 2014 Regulatory Assets: Accumulated deferred income taxes $ 291 $ 278 AROs and related funding 384 347 Deferred employee benefit plan costs 295 310 Deferred losses on interest rate derivatives 535 453 Unrecovered plant 127 137 Environmental remediation costs 35 36 DSM Programs 61 56 Other 129 128 Total Regulatory Assets $ 1,857 $ 1,745 Regulatory Liabilities: Asset removal costs 519 505 Deferred gains on interest rate derivatives 96 82 Other 20 23 Total Regulatory Liabilities $ 635 $ 610 Accumulated deferred income tax liabilities that arose from utility operations that have not been included in customer rates are recorded as a regulatory asset. Substantially all of these regulatory assets relate to AFC and are expected to be recovered over the remaining lives of the related property which may range up to approximately 85 years. ARO 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 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. Accordingly, 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 12 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 will amortize 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 and are expected to be recoverable over periods of up to approximately 24 years. DSM Programs represent deferred costs associated with such programs. As a result of an April 2015 SCPSC order, deferred costs are currently being recovered over approximately five years through an approved rate rider. Various other regulatory assets are expected to be recovered in rates over periods of up to approximately 30 years. 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 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 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 received by SCE&G. 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, Consolidated SCE&G could be required to write off its regulatory assets and liabilities. Such an event could have a material effect on Consolidated SCE&G's results of operations, liquidity or financial position in the period the write-off would be recorded.

COMMON EQUITY

COMMON EQUITY	12 Months Ended
	Dec. 31, 2015
Schedule of Capitalization, Equity [Line Items]
Stockholders' Equity Note Disclosure [Text Block]	COMMON EQUITY The Company’s articles of incorporation do not limit the dividends that may be paid on its 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 considers 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, 2015 and 2014, retained earnings of approximately $72.4 million and $67.7 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, 2015 and 2014. SCANA issued common stock valued at $14.3 million , $99.3 million and $100.9 million (when issued) during the years ended December 31, 2015, 2014 and 2013, respectively, to satisfy the requirements of various compensation and dividend reinvestment plans. In addition, in March 2013, SCANA settled all forward sales contracts related to its common stock through the issuance of approximately 6.6 million common shares, resulting in net proceeds of approximately $196.2 million .
SCE&G
Schedule of Capitalization, Equity [Line Items]
Stockholders' Equity Note Disclosure [Text Block]	EQUITY Authorized shares of SCE&G common stock were 50 million as of December 31, 2015 and 2014. 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, 2015 and 2014. SCE&G’s articles of incorporation do not limit the dividends that may be paid on its common stock. However, SCE&G’s bond indenture contains provisions that, under certain circumstances, which SCE&G considers to be remote, could limit the payment of cash dividends on its common stock. The Federal Power Act requires the appropriation of a portion of certain earnings from hydroelectric projects. At December 31, 2015 and 2014, retained earnings of approximately $72.4 million and $67.7 million , respectively, were restricted by this requirement as to payment of cash dividends on common stock.

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 Total long-term debt, net reflects the retrospective adoption of accounting guidance for unamortized debt issuance costs in the fourth quarter of 2015 (see Note 1). Long-term debt by type with related weighted average effective interest rates and maturities at December 31 is as follows: 2015 2014 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) 2016 - 2034 84 1.11 % 88 0.93 % SCE&G First Mortgage Bonds (secured) 2018 - 2065 4,340 5.78 % 3,840 5.56 % GENCO Notes (secured) 2016 - 2024 220 5.92 % 227 5.90 % Industrial and Pollution Control Bonds (b) 2028 - 2038 122 3.51 % 122 3.51 % PSNC Senior Debentures 2020 - 2026 350 5.93 % 350 5.93 % Nuclear Fuel Financing 2016 100 0.78 % 100 0.78 % Other (c) 2016 - 2027 18 2.72 % 167 7.39 % Total debt 6,034 5,694 Current maturities of long-term debt (116 ) (166 ) Unamortized premium, net — 3 Unamortized debt issuance costs (36 ) (34 ) Total long-term debt, net $ 5,882 $ 5,497 (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, 2015 (rate of 0.03% ) and 2014 (rate of 0.04% ) which are hedged by fixed swaps. (c) Includes Junior Subordinated Notes redeemed at par prior to maturity on February 2, 2015, and included in the current portion of long-term debt on the balance sheet at December 31, 2014. 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. In May 2014, SCE&G issued $300 million of 4.5% first mortgage bonds due June 1, 2064. 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. Long-term debt maturities will be $116 million in 2016, $15 million in 2017, $724 million in 2018, $13 million in 2019 and $363 million in 2020. 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, 2015, the Bond Ratio was 5.17 . Lines of Credit and Short-Term Borrowings At December 31, 2015 and 2014, 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: SCANA SCE&G PSNC Energy Millions of dollars 2015 2014 2015 2014 2015 2014 Lines of Credit: Total committed long-term $ 400 $ 300 $ 1,400 $ 1,400 $ 200 $ 100 Outstanding commercial paper (270 or fewer days) $ 37 $ 179 $ 420 $ 709 $ 74 $ 30 Weighted average interest rate 1.19 % 0.54 % 0.74 % 0.52 % 0.77 % 0.65 % Letters of credit supported by LOC $ 3 $ 3 $ 0.3 $ 0.3 — — Available $ 360 $ 118 $ 980 $ 691 $ 126 $ 70 SCANA, SCE&G (including Fuel Company) and PSNC Energy are parties to five-year credit agreements in the amounts of $400 million, $1.2 billion (of which $500 million relates to Fuel Company) and $200 million, respectively. In addition, SCE&G is party to a three-year credit agreement in the amount of $200 million . In December 2015, the term of the five -year agreements was amended and extended by one year, such that they expire in December 2020. The three -year agreement expires in December 2018. 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. On January 29, 2015, SCANA entered into an unsecured, three-month credit agreement in the amount of $150 million . SCANA entered this agreement to ensure sufficient liquidity was available to redeem its junior subordinated notes on February 2, 2015. No borrowings were made under this agreement, and it expired according to its terms on February 6, 2015. The Company 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.
SCE&G
Debt Instrument [Line Items]
Debt Disclosure [Text Block]	LONG-TERM AND SHORT-TERM DEBT Total long-term debt, net reflects the retrospective adoption of accounting guidance for unamortized debt issuance costs in the fourth quarter of 2015 (see Note 1). Long-term debt by type with related weighted average effective interest rates and maturities at December 31 is as follows: 2015 2014 Dollars in millions Maturity Balance Rate Balance Rate First Mortgage Bonds (secured) 2018 - 2065 $ 4,340 5.78 % $ 3,840 5.56 % GENCO Notes (secured) 2016 - 2024 220 5.92 % 227 5.90 % Industrial and Pollution Control Bonds (a) 2028 - 2038 122 3.51 % 122 3.51 % Nuclear Fuel Financing 2016 100 0.78 % 100 0.78 % Other 2016 - 2027 17 2.63 % 14 2.63 % Total debt 4,799 4,303 Current maturities of long-term debt (110 ) (10 ) Unamortized premium, net 2 6 Unamortized debt issuance costs (32 ) (29 ) Total long-term debt, net $ 4,659 $ 4,270 (a) Includes variable rate debt of $67.8 million at December 31, 2015 (rate of 0.03% ) and 2014 (rate of 0.04% ), which are hedged by fixed swaps. 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. In May 2014, SCE&G issued $300 million of 4.5% first mortgage bonds due June 1, 2064. 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. Long-term debt maturities will be $110 million in 2016, $10 million in 2017, $720 million in 2018, $9 million in 2019 and $8 million in 2020. 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, 2015, the Bond Ratio was 5.17 . Lines of Credit and Short-Term Borrowings At December 31, 2015 and 2014, SCE&G (including Fuel Company) had available the following committed LOC and had outstanding the following LOC-related obligations and commercial paper borrowings: Millions of dollars 2015 2014 Lines of credit: Total committed long-term $ 1,400 $ 1,400 Outstanding commercial paper (270 or fewer days) $ 420 $ 709 Weighted average interest rate 0.74 % 0.52 % Letters of credit supported by an LOC $ 0.3 $ 0.3 Available $ 980 $ 691 SCE&G and Fuel Company are parties to five-year credit agreements in the amount of $ 1.2 billion (of which $500 million relates to Fuel Company). In addition, SCE&G is party to a three-year credit agreement in the amount of $200 million . In December 2015, the term of the five -year agreements was amended and extended by one year, such that they expire in December 2020. The three -year agreement expires in December 2018. 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. Consolidated SCE&G pays fees to the banks as compensation for maintaining the committed lines of credit. Such fees were not material in any period presented. Consolidated SCE&G is obligated with respect to an aggregate of $67.8 million of industrial revenue bonds which are secured by letters of credit issued by TD Bank N.A. These letters of credit expire, subject to renewal, in the fourth quarter of 2019. Consolidated SCE&G participates in a utility money pool with SCANA and 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, 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 . At December 31, 2014 Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $83 million and money pool investments due from an affiliate of $80 million . On the 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, 2015
income tax [Line Items]
Income Tax Disclosure [Text Block]	INCOME TAXES Components of income tax expense are as follows: Millions of dollars 2015 2014 2013 Current taxes: Federal $ 382 $ 38 $ 161 State 57 (4 ) 17 Total current taxes 439 34 178 Deferred tax (benefit) expense, net: Federal (36 ) 184 39 State (7 ) 34 10 Total deferred taxes (43 ) 218 49 Investment tax credits: Amortization of amounts deferred-state (1 ) (1 ) (1 ) Amortization of amounts deferred-federal (2 ) (3 ) (3 ) Total investment tax credits (3 ) (4 ) (4 ) Total income tax expense $ 393 $ 248 $ 223 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: Millions of dollars 2015 2014 2013 Net income $ 746 $ 538 $ 471 Income tax expense 393 248 223 Total pre-tax income $ 1,139 $ 786 $ 694 Income taxes on above at statutory federal income tax rate $ 399 $ 275 $ 243 Increases (decreases) attributed to: State income taxes (less federal income tax effect) 38 24 22 State investment tax credits (less federal income tax effect) (6 ) (5 ) (5 ) Allowance for equity funds used during construction (9 ) (11 ) (9 ) Deductible dividends—401(k) Retirement Savings Plan (10 ) (10 ) (10 ) Amortization of federal investment tax credits (2 ) (3 ) (3 ) Section 41 tax credits 1 (3 ) — Section 45 tax credits (9 ) (9 ) (5 ) Domestic production activities deduction (18 ) (7 ) (11 ) Realization of basis differences upon sale of subsidiaries 7 — — Other differences, net 2 (3 ) 1 Total income tax expense $ 393 $ 248 $ 223 The tax effects of significant temporary differences comprising the Company’s net deferred tax liability are as follows: Millions of dollars 2015 2014 Deferred tax assets: Nondeductible accruals $ 135 $ 127 Asset retirement obligation, including nuclear decommissioning 199 216 Financial instruments 35 40 Unamortized investment tax credits 16 17 Deferred fuel costs 8 — Monetization of bankruptcy claim — 10 Other 5 10 Total deferred tax assets 398 420 Deferred tax liabilities: Property, plant and equipment $ 1,906 $ 1,928 Deferred employee benefit plan costs 96 107 Regulatory asset, asset retirement obligation 135 122 Deferred fuel costs — 27 Regulatory asset, unrecovered plant 49 53 Regulatory asset, net loss on interest rate derivative contracts settlement — 21 Demand side management costs 23 21 Prepayments 31 27 Other 65 45 Total deferred tax liabilities 2,305 2,351 Net deferred tax liability $ 1,907 $ 1,931 During the third quarter of 2013, the State of North Carolina passed legislation that lowered the state corporate income tax rate from 6.9% to 6.0% in 2014, 5.0% in 2015 and 4.0% in 2016. In connection with this change in tax rates, related state deferred tax amounts were remeasured, with the change in their balances being credited to a regulatory liability. The change in income tax rates did not and is 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, 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 2014 as a result of claims discussed below in Changes to Unrecognized Tax Benefits. With few exceptions, the Company is no longer subject to state and local income tax examinations by tax authorities for years before 2010. Changes to Unrecognized Tax Benefits Millions of dollars 2015 2014 2013 Unrecognized tax benefits, January 1 $ 16 $ 3 — Gross increases—uncertain tax positions in prior period 33 — — Gross decreases—uncertain tax positions in prior period (2 ) — — Gross increases—current period uncertain tax positions 2 13 $ 3 Unrecognized tax benefits, December 31 $ 49 $ 16 $ 3 During 2013 and 2014, the Company amended certain of its tax returns to claim certain tax-defined research and development deductions and credits and its related impact on domestic production activities. The Company also made similar claims in filing its 2013 and 2014 returns in 2014 and 2015, respectively. In connection with these federal and state filings, the Company recorded an unrecognized tax benefit of $49 million . During 2015, as the IRS' examination of these claims progressed, without resolution, the Company evaluated and recorded adjustments to its unrecognized tax benefits; however, none of these changes materially affected the Company's effective tax rate. If recognized, $17 million of the tax benefits would affect the Company's effective tax rate. It is reasonably possible that these tax benefits will increase by an additional $7 million within the next 12 months. It is also reasonably possible that these tax benefits may decrease by $8 million within the next 12 months. No other material changes in the status of the Company’s tax positions have occurred through December 31, 2015. The Company recognizes interest accrued related to unrecognized tax benefits within interest expense or interest income and recognizes tax penalties within other expenses. In connection with the resolution of the uncertainty and recognition of the tax benefit, the Company has not recorded a material amount of interest income, interest expense, or penalties associated with any uncertain tax position.
SCE&G
income tax [Line Items]
Income Tax Disclosure [Text Block]	INCOME TAXES Components of income tax expense are as follows: Millions of dollars 2015 2014 2013 Current taxes: Federal $ 208 $ 39 $ 146 State 32 (6 ) 13 Total current taxes 240 33 159 Deferred tax (benefit) expense, net: Federal (3 ) 157 25 State (3 ) 32 9 Total deferred taxes (6 ) 189 34 Investment tax credits: Amortization of amounts deferred—state (1 ) (1 ) (1 ) Amortization of amounts deferred—federal (2 ) (3 ) (3 ) Total investment tax credits (3 ) (4 ) (4 ) Total income tax expense $ 231 $ 218 $ 189 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: Millions of dollars 2015 2014 2013 Net income $ 466 $ 446 $ 380 Income tax expense 231 218 189 Noncontrolling interest 14 12 11 Total pre-tax income $ 711 $ 676 $ 580 Income taxes on above at statutory federal income tax rate $ 249 $ 237 $ 203 Increases (decreases) attributed to: State income taxes (less federal income tax effect) 24 21 18 State investment tax credits (less federal income tax effect) (6 ) (5 ) (5 ) Allowance for equity funds used during construction (9 ) (10 ) (9 ) Amortization of federal investment tax credits (2 ) (3 ) (3 ) Section 41 tax credits 1 (3 ) — Section 45 tax credits (9 ) (9 ) (5 ) Domestic production activities deduction (18 ) (7 ) (11 ) Other differences, net 1 (3 ) 1 Total income tax expense $ 231 $ 218 $ 189 The tax effects of significant temporary differences comprising Consolidated SCE&G’s net deferred tax liability are as follows: Millions of dollars 2015 2014 Deferred tax assets: Nondeductible accruals $ 52 $ 47 Asset retirement obligation, including nuclear decommissioning 187 205 Unamortized investment tax credits 16 17 Deferred fuel costs 7 — Financial instruments 2 — Other 2 6 Total deferred tax assets 266 275 Deferred tax liabilities: Property, plant and equipment $ 1,644 $ 1,623 Regulatory asset, asset retirement obligation 127 115 Deferred employee benefit plan costs 85 91 Deferred fuel costs — 27 Regulatory asset, unrecovered plant 49 53 Regulatory asset, net loss on interest rate derivative contracts settlement — 21 Demand side management costs 23 21 Prepayments 29 25 Other 41 23 Total deferred tax liabilities 1,998 1,999 Net deferred tax liability $ 1,732 $ 1,724 Consolidated SCE&G is included in the consolidated federal income tax return of SCANA and files various applicable state and local income tax returns. The IRS has completed examinations of SCANA’s federal returns through 2004, and SCANA’s federal returns through 2007 are closed for additional assessment. The IRS is currently examining SCANA's open federal returns through 2014 as a result of claims discussed below in Changes to Unrecognized Tax Benefits. With few exceptions, Consolidated SCE&G is no longer subject to state and local income tax examinations by tax authorities for years before 2010. Changes to Unrecognized Tax Benefits Millions of dollars 2015 2014 2013 Unrecognized tax benefits, January 1 $ 16 $ 3 — Gross increases-uncertain tax positions in prior period 33 — — Gross decreases-uncertain tax positions in prior period (2 ) — — Gross increases-current period uncertain tax positions 2 13 $ 3 Unrecognized tax benefits, December 31 $ 49 $ 16 $ 3 During 2013 and 2014, Consolidated SCE&G amended certain of its tax returns to claim certain tax-defined research and development deductions and credits and its related impact on domestic production activities. Consolidated SCE&G also made similar claims in filing its 2013 and 2014 returns in 2014 and 2015, respectively. In connection with these federal and state filings, Consolidated SCE&G recorded an unrecognized tax benefit of $49 million . During 2015, as the IRS' examination progressed, without resolution, Consolidated SCE&G evaluated and recorded adjustments to its unrecognized tax benefits; however, none of these changes materially affected Consolidated SCE&G's effective tax rate. If recognized, $17 million of the tax benefits would affect Consolidated SCE&G's effective tax rate. It is reasonably possible that these tax benefits will increase by an additional $7 million within the next 12 months. It is also reasonably possible that these tax benefits may decrease by $ 8 million within the next 12 months. No other material changes in the status of Consolidated SCE&G's tax positions have occurred through December 31, 2015. Consolidated SCE&G recognizes interest accrued related to unrecognized tax benefits within interest expense or interest income and recognizes tax penalties within other expenses. In connection with the resolution of the uncertainty and recognition of the tax benefit, Consolidated SCE&G has not recorded a material amount of interest income, interest expense, or penalties associated with any uncertain tax position.

DERIVATIVE FINANCIAL INSTRUMENT

DERIVATIVE FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2015
Derivative [Line Items]
Derivative Instruments and Hedging Activities Disclosure [Text Block]	6. DERIVATIVE FINANCIAL INSTRUMENTS The Company recognizes all derivative instruments as either assets or liabilities in its statements of financial position and measures those instruments at fair value. The Company recognizes changes in the fair value of derivative instruments either in earnings, as a component of other comprehensive income (loss) or, for regulated subsidiaries, within regulatory assets or regulatory liabilities, depending upon the intended use of the derivative and the resulting designation. Policies and procedures and risk limits are established to control the level of market, credit, liquidity and operational and administrative risks assumed by the Company. 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 Company’s Risk Management Officer and 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 statement of cash flows. PSNC Energy hedges natural gas purchasing activities using over-the-counter options and swaps and NYMEX futures and options. PSNC Energy’s tariffs also 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 over- or under-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, SEMI, 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 The Company may use interest rate swaps 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 the Company synthetically converts variable rate debt to fixed rate debt using swaps that are designated as cash flow hedges, periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense. In anticipation of the issuance of debt, the Company may use treasury rate lock or forward starting swap agreements that are designated as cash flow hedges. 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 the holding company or 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 derivatives entered into by SCE&G after October 2013 are not designated as cash flow hedges and fair value changes and settlement amounts 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 applied to under-collected fuel, may be amortized to interest expense or may be applied as otherwise directed by the SCPSC. As discussed in Note 2, in 2013 the SCPSC directed SCE&G to recognize $41.6 million and $8.5 million of realized gains (which had been deferred in regulatory liabilities) within other income in 2013, fully offsetting revenue reductions related to under-collected fuel balances and under-collected amounts arising under the eWNA program which was terminated at the end of 2013. As also discussed in Note 2, pursuant to regulatory orders in 2014, the SCPSC directed SCE&G to apply $46 million of these deferred gains to reduce under-collected fuel to utilize approximately $17.8 million of these gains to offset a portion of the net lost revenues component of SCE&G’s DSM Program rider, and to apply $5.0 million of the gains to the remaining balance of deferred net lost revenues as of April 30, 2014, which had been deferred within regulatory assets. Cash payments made or received upon settlement 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 Retail Gas Marketing Energy Marketing Total As of December 31, 2015 Commodity 7,530,000 7,869,000 3,973,500 19,372,500 Energy Management (a) — — 38,857,480 38,857,480 Total (a) 7,530,000 7,869,000 42,830,980 58,229,980 As of December 31, 2014 Commodity 6,840,000 7,951,000 3,446,720 18,237,720 Energy Management (b) — — 37,495,339 37,495,339 Total (b) 6,840,000 7,951,000 40,942,059 55,733,059 (a) Includes an aggregate 1,842,048 MMBTU related to basis swap contracts in Energy Marketing. (b) Includes an aggregate 933,893 MMBTU related to basis swap contracts in Energy Marketing. The Company was party to interest rate swaps designated as cash flow hedges with aggregate notional amounts of $120.0 million at December 31, 2015 and $124.4 million at December 31, 2014. The Company was party to interest rate swaps not designated as cash flow hedges with an aggregate notional amount of $1.235 billion and $1.085 billion at December 31, 2015 and 2014, respectively. The fair value of derivatives in the consolidated balance sheets is as follows: Fair Values of Derivative Instruments Millions of dollars Balance Sheet Location Asset Liability As of December 31, 2015 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 4 Other deferred credits and other liabilities 28 Commodity contracts Other current assets 1 Derivative financial instruments 4 Total $ 37 Not designated as hedging instruments Interest rate contracts Other current assets $ 10 Other deferred debits and other assets 5 Derivative financial instruments $ 33 Other deferred credits and other liabilities 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 As of December 31, 2014 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 5 Other deferred credits and other liabilities 28 Commodity contracts Other current assets 1 Derivative financial instruments 11 Total $ 45 Not designated as hedging instruments Interest rate contracts Derivative financial instruments $ 207 Other deferred credits and other liabilities 17 Commodity contracts Other current assets $ 1 Energy management contracts Other current assets 15 5 Other deferred debits and other assets 5 Derivative financial instruments 10 Other deferred credits and other liabilities 5 Total $ 21 $ 244 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: Gain or (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, 2015 Interest rate contracts $ (3 ) Interest expense $ (3 ) Year Ended December 31, 2014 Interest rate contracts $ (9 ) Interest expense $ (3 ) Year Ended December 31, 2013 Interest rate contracts $ 106 Interest expense $ (3 ) 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, 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 ) Year Ended December 31, 2013 Interest rate contracts $ 5 Interest expense $ (8 ) Commodity contracts 2 Gas purchased for resale (3 ) Total $ 7 $ (11 ) As of December 31, 2015, the Company expects that during the next 12 months reclassifications from accumulated other comprehensive loss to earnings arising from cash flow hedges will include approximately $3.3 million as an increase to gas cost and approximately $7.1 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels. As of December 31, 2015, all of the Company’s commodity cash flow hedges settle by their terms before the end of the second quarter of 2018. As of December 31, 2015, the Company expects that during the next twelve months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $2.2 million as an increase to interest expense assuming financial markets remain at their current levels. Hedge Ineffectiveness Other gain (losses) recognized in income representing ineffectiveness on interest rate hedges designated as cash flow hedges were insignificant for all periods presented. Derivatives Not Designated as Hedging Instruments Gain (Loss) Deferred in Regulatory Accounts Gain Reclassified from Deferred Accounts into Income Millions of dollars Location Amount Year Ended December 31, 2015 Interest rate contracts $ (69 ) Other income $ 5 Year Ended December 31, 2014 Interest rate contracts $ (352 ) Other income $ 64 Year Ended December 31, 2013 Interest rate contracts $ 39 Other income $ 50 Gains reclassified to other income offset revenue reductions as previously described herein and in Note 2. As of December 31, 2015, the Company expects that during the next twelve months reclassifications from regulatory accounts to earnings arising from interest rate swaps not designated as cash flow hedges will include approximately $0.6 million as an increase to interest expense. Credit Risk Considerations The Company limits credit risk in its commodity and interest rate derivatives activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. In this regard, the Company uses credit ratings provided by credit rating agencies and current market-based qualitative and quantitative data, as well as financial statements, to assess the financial health of counterparties on an ongoing basis. The Company uses standardized master agreements which generally include collateral requirements. These master agreements permit the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with the Company's credit policies and due diligence. In addition, collateral agreements allow for the termination and liquidation of all positions in the event of a failure or inability to post collateral. Certain of the Company’s derivative instruments contain contingent provisions that require the Company to provide collateral upon the occurrence of specific events, primarily credit rating downgrades. As of December 31, 2015 and 2014, the Company had posted $50.4 million and $152.4 million , respectively, of collateral related to derivatives with contingent provisions that were in a net liability position. Collateral related to the positions expected to close in the next 12 months is recorded in Other Current Assets on the consolidated balance sheets. Collateral related to the noncurrent positions is recorded in Other within Deferred Debits and Other Assets on the consolidated balance sheets. If all of the contingent features underlying these instruments had been fully triggered as of December 31, 2015 and 2014, the Company would have been required to post an additional $44.8 million and $129.8 million , respectively, of collateral to its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of December 31, 2015 and 2014, are $95.2 million and $282.2 million , respectively. In addition, as of December 31, 2015 and December 31, 2014, the Company has collected no cash collateral related to interest rate derivatives with contingent provisions that are in a net asset position. If all the contingent features underlying these instruments had been fully triggered as of December 31, 2015 and December 31, 2014, the Company could request $7.3 million and $- million, respectively, of cash collateral from its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net asset position as of December 31, 2015 and December 31, 2014 is $7.3 million and $- million, respectively. In addition, at December 31, 2015, the Company could have called on letters of credit in the amount of $3.0 million related to $14.0 million in commodity derivatives that are in a net asset position, compared to letters of credit of $9.2 million related to derivatives of $20 million at December 31, 2014, if all the contingent features underlying these instruments had been fully triggered. Information related to the Company's offsetting derivative assets and liabilities follows: Offsetting Derivative Assets Gross Amounts Offset in the Statement of Financial Position Net Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position Net Amount Millions of dollars Gross Amounts of Recognized Assets Financial Instruments Cash Collateral Received As of December 31, 2015 Interest rate $ 15 — $ 15 $ (8 ) — $ 7 Commodity 1 — 1 — — 1 Energy Management 15 $ (1 ) 14 — — 14 Total $ 31 $ (1 ) $ 30 $ (8 ) — $ 22 Balance sheet location Other current assets $ 22 Other deferred debits and other assets 8 Total $ 30 As of December 31, 2014 Commodity $ 1 — $ 1 — — $ 1 Energy Management 20 — 20 — — 20 Total $ 21 — $ 21 — — $ 21 Balance sheet location Other current assets $ 16 Other deferred debits and other assets 5 Total $ 21 Offsetting Derivative Liabilities Gross Amounts Offset in the Statement of Financial Position Net Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position Net Amount Millions of dollars Gross Amounts of Recognized Liabilities Financial Instruments Cash Collateral Posted As of December 31, 2015 Interest rate $ 87 — $ 87 $ (8 ) $ (36 ) $ 43 Commodity 5 — 5 — (5 ) — Energy Management 15 $ (1 ) 14 — (9 ) 5 Total $ 107 $ (1 ) $ 106 $ (8 ) $ (50 ) $ 48 Balance sheet location Other current assets $ 3 Derivative financial instruments 50 Other deferred credits and other liabilities 53 Total $ 106 As of December 31, 2014 Interest rate $ 257 — $ 257 — $ (131 ) $ 126 Commodity 12 — 12 — (10 ) 2 Energy Management 20 — 20 — (11 ) 9 Total $ 289 — $ 289 — $ (152 ) $ 137 Balance sheet location Other current assets $ 6 Derivative financial instruments 233 Other deferred credits and other liabilities 50 Total $ 289
SCE&G
Derivative [Line Items]
Derivative Instruments and Hedging Activities Disclosure [Text Block]	DERIVATIVE FINANCIAL INSTRUMENTS Consolidated SCE&G recognizes all derivative instruments as either assets or liabilities in its statements of financial position and measures those instruments at fair value. Consolidated SCE&G recognizes changes in the fair value of derivative instruments either in earnings or within regulatory assets or regulatory liabilities, depending upon the intended use of the derivative and the resulting designation. Policies and procedures and risk limits are established to control the level of market, credit, liquidity and operational and administrative risks assumed by Consolidated SCE&G. 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, including Consolidated SCE&G. The Risk Management Committee, which is comprised of certain officers, including Consolidated SCE&G’s Risk Management Officer and 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. Interest Rate Swaps Consolidated SCE&G synthetically converts variable rate debt to fixed rate debt using swaps that are designated as cash flow hedges. Periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense. In anticipation of the issuance of debt, Consolidated SCE&G may use treasury rate lock or forward starting swap agreements. Pursuant to regulatory orders, interest derivatives entered into by SCE&G after October 2013 are not designated as cash flow hedges, and fair value changes and settlement amounts 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 applied to under-collected fuel, may be amortized to interest expense or may be applied as otherwise directed by the SCPSC. As discussed in Note 2, in 2013 the SCPSC directed SCE&G to recognize $41.6 million and $8.5 million of realized gains (which had been deferred in regulatory liabilities) within other income in 2013, fully offsetting revenue reductions related to under-collected fuel balances and under-collected amounts arising under the eWNA program which was terminated at the end of 2013. As also discussed in Note 2, pursuant to regulatory orders in 2014, the SCPSC directed SCE&G to apply $46 million of these deferred gains to reduce under-collected fuel to utilize approximately $17.8 million of these gains to offset a portion of the net lost revenues component of SCE&G’s DSM Program rider, and to apply $5.0 million of the gains to the remaining balance of deferred net lost revenues as of April 30, 2014, which had been deferred within regulatory assets. Cash payments made or received upon settlement of these financial instruments are classified as investing activities for cash flow statement purposes. Quantitative Disclosures Related to Derivatives Consolidated SCE&G was a party to interest rate swaps designated as cash flow hedges with aggregate notional amounts of $36.4 million and $36.4 million at December 31, 2015 and 2014, respectively. Consolidated SCE&G was party to interest rate swaps not designated as cash flow hedges with an aggregate notional amount of $1.235 billion and $1.085 billion at December 31, 2015 and 2014, respectively. The fair value of derivatives in the consolidated balance sheets is as follows: Fair Values of Derivative Instruments Millions of dollars Balance Sheet Location Asset Liability As of December 31, 2015 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 1 Other deferred credits and other liabilities 9 Total $ 10 Not designated as hedging instruments Interest rate contracts Other current assets $ 10 Other deferred debits and other assets 5 Derivative financial instruments $ 33 Other deferred credits and other liabilities 22 Total $ 15 $ 55 As of December 31, 2014 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 1 Other deferred credits and other liabilities 8 Total $ 9 Not designated as hedging instruments Interest rate contracts Derivative financial instruments $ 207 Other deferred credits and other liabilities 17 Total $ 224 The effect of derivative instruments on the consolidated statements of income is as follows: Derivatives in Cash Flow Hedging Relationships Gain (Loss) Deferred in Regulatory Accounts (Effective Portion) Gain (Loss) Reclassified from Deferred Accounts into Income (Effective Portion) Millions of dollars Location Amount Year Ended December 31, 2015 Interest rate contracts $ (3 ) Interest expense $ (3 ) Year Ended December 31, 2014 Interest rate contracts $ (9 ) Interest expense $ (3 ) Year Ended December 31, 2013 Interest rate contracts $ 106 Interest expense $ (3 ) As of December 31, 2015, Consolidated SCE&G expects that during the next twelve months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $2.2 million as an increase to interest expense assuming financial markets remain at their current levels. Hedge Ineffectiveness Other gains (losses) recognized in income representing ineffectiveness on interest rate hedges designated as cash flow hedges were insignificant for all periods presented. Gain or (Loss) Deferred in Regulatory Accounts Gain Reclassified from Deferred Accounts into Income Millions of dollars Location Amount Year Ended December 31, 2015 Interest rate contracts $ (69 ) Other income $ 5 Year Ended December 31, 2014 Interest rate contracts $ (352 ) Other income $ 64 Year Ended December 31, 2013 Interest rate contracts $ 39 Other income $ 50 The gains reclassified to other income offset revenue reductions as previously described herein and in Note 2. As of December 31, 2015, Consolidated SCE&G expects that during the next twelve months reclassifications from regulatory accounts to earnings arising from interest rate swaps not designated as cash flow hedges will include approximately $0.6 million as an increase to interest expense. Credit Risk Considerations Consolidated SCE&G limits credit risk in its derivatives activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. In this regard, Consolidated SCE&G uses credit ratings provided by credit rating agencies and current market-based qualitative and quantitative data, as well as financial statements, to assess the financial health of counterparties on an ongoing basis. Consolidated SCE&G uses standardized master agreements which generally include collateral requirements. These master agreements permit the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with Consolidated SCE&G's credit policies and due diligence. In addition, collateral agreements allow for the termination and liquidation of all positions in the event of a failure or inability to post collateral. Certain of Consolidated SCE&G’s derivative instruments contain contingent provisions that require Consolidated SCE&G to provide collateral upon the occurrence of specific events, primarily credit rating downgrades. As of December 31, 2015 and 2014, Consolidated SCE&G had posted $13.4 million and $107.1 million , respectively, of collateral related to derivatives with contingent provisions that were in a net liability position. Collateral related to the positions expected to close in the next 12 months are recorded in Other Current Assets on the consolidated balance sheets. Collateral related to the noncurrent positions is recorded in Other within Deferred Debits and Other Assets on the consolidated balance sheets. If all of the contingent features underlying these instruments had been fully triggered as of December 31, 2015 and 2014, Consolidated SCE&G would have been required to post an additional $43.6 million and $125.9 million , respectively, of collateral to its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of December 31, 2015 and 2014, are $57.0 million and $233.0 million , respectively. In addition, as of December 31, 2015 and December 31, 2014, Consolidated SCE&G has collected no cash collateral related to interest rate derivatives with contingent provisions that are in a net asset position. If all the contingent features underlying these instruments had been fully triggered as of December 31, 2015 and December 31, 2014, Consolidated SCE&G could request $7.3 million and $- million, respectively, of cash collateral from its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net asset position as of December 31, 2015 and December 31, 2014 is $7.3 million and $- million, respectively. Information related to Consolidated SCE&G's offsetting derivative assets and liabilities follows: Offsetting Derivative Assets Gross Amounts Offset in the Statement of Financial Position Net Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position Net Amount Millions of dollars Gross Amounts of Recognized Assets Financial Instruments Cash Collateral Received As of December 31, 2015 Interest rate $ 15 — $ 15 $ (8 ) — $ 7 Balance sheet location Other current assets $ 10 Other deferred debits and other assets 5 Total $ 15 As of December 31, 2014 Consolidated SCE&G had no derivative assets. Offsetting Derivative Liabilities Gross Amounts Offset in the Statement of Financial Position Net Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position Net Amount Millions of dollars Gross Amounts of Recognized Liabilities Financial Instruments Cash Collateral Posted As of December 31, 2015 Interest rate $ 65 — $ 65 $ (8 ) $ (13 ) $ 44 Balance sheet location Derivative financial instruments $ 34 Other deferred credits and other liabilities 31 Total $ 65 As of December 31, 2014 Interest rate $ 233 — $ 233 — $ (107 ) $ 126 Balance sheet location Derivative financial instruments $ 208 Other deferred credits and other liabilities 25 Total $ 233

FAIR VALUE MEASUREMENTS, INCLUD

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES	12 Months Ended
	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Disclosures [Text Block]	7. FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES The Company values available for sale securities 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. The Company’s interest rate swap agreements are valued using discounted cash flow models with independently sourced data. Fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows: As of December 31, 2015 As of December 31, 2014 Millions of dollars Level 1 Level 2 Level 1 Level 2 Assets: Available for sale securities $ 11 — $ 13 — Interest rate contracts — $ 15 — — Commodity contracts 1 — 1 — Energy management contracts — 14 — $ 20 Liabilities: Interest rate contracts — 87 — 257 Commodity contracts 1 4 1 11 Energy management contracts 4 12 5 18 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, 2015 and December 31, 2014 were as follows: As of December 31, 2015 As of December 31, 2014 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Long-term debt $ 5,997.6 $ 6,445.7 $ 5,663.1 $ 6,558.0 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 Consolidated SCE&G’s interest rate swap agreements are valued using discounted cash flow models with independently sourced data. Fair value Level 2 measurements were as follows: As of December 31, 2015 As of December 31, 2014 Millions of dollars Level 2 Level 2 Assets-Interest rate contracts $ 15 — Liabilities-Interest rate contracts 65 $ 233 There were no Level 1 or 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, 2015 and December 31, 2014 were as follows: As of December 31, 2015 As of December 31, 2014 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Long-term debt $ 4,769.0 $ 5,129.1 $ 4,279.5 $ 5,041.9 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, 2015
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 The Company sponsors a noncontributory defined benefit pension plan covering regular, full-time employees hired before January 1, 2014. The Company’s policy has been to fund the plan as permitted by applicable federal income tax regulations, as determined by an independent actuary. The Company’s pension plan provides benefits under a cash balance formula for employees hired before January 1, 2000 who elected that option and for 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, the Company provides certain unfunded postretirement health care and life insurance benefits to certain active and retired employees. 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. 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. Pension Benefits Other Postretirement Benefits Millions of dollars 2015 2014 2015 2014 Benefit obligation, January 1 $ 919.5 $ 823.0 $ 268.2 $ 238.0 Service cost 24.1 20.0 5.3 4.6 Interest cost 38.2 40.4 11.4 12.0 Plan participants’ contributions — — 2.4 2.2 Actuarial (gain) loss (62.4 ) 100.1 (21.2 ) 23.5 Benefits paid (64.0 ) (64.0 ) (12.5 ) (12.1 ) Benefit obligation, December 31 $ 855.4 $ 919.5 $ 253.6 $ 268.2 The Company adopted new mortality tables and an improvement scale published by the Society of Actuaries in 2014, resulting in an actuarial loss for pension and other post retirement benefit obligations of approximately $26.3 million and $2.7 million , respectively, in 2014. In 2015, based on an evaluation of the mortality experience of the pension plan, the Company adopted a custom mortality table 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 of approximately $21.5 million and $2.4 million , respectively, in 2015. The accumulated benefit obligation for pension benefits was $ 829.3 million at the end of 2015 and $ 888.3 million at the end of 2014. 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 2015 2014 2015 2014 Annual discount rate used to determine benefit obligation 4.68 % 4.20 % 4.78 % 4.30 % Assumed annual rate of future salary increases for projected benefit obligation 3.00 % 3.00 % 3.00 % 3.00 % A 7.0% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2015. 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 would increase the postretirement benefit obligation by $0.8 million at December 31, 2015 and by $1.3 million at December 31, 2014. A one percent decrease in the assumed health care cost trend rate would decrease the postretirement benefit obligation by $0.7 million at December 31, 2015 and by $1.0 million at December 31, 2014. Funded Status Millions of Dollars Pension Benefits Other Postretirement Benefits December 31, 2015 2014 2015 2014 Fair value of plan assets $ 781.7 $ 861.8 — — Benefit obligation 855.4 919.5 $ 253.6 $ 268.2 Funded status $ (73.7 ) $ (57.7 ) $ (253.6 ) $ (268.2 ) Amounts recognized on the consolidated balance sheets were as follows: Millions of Dollars Pension Benefits Other Postretirement Benefits December 31, 2015 2014 2015 2014 Current liability — — $ (11.9 ) $ (11.2 ) Noncurrent liability $ (73.7 ) $ (57.7 ) (241.7 ) (257.0 ) Amounts recognized in accumulated other comprehensive loss were as follows: Millions of Dollars Pension Benefits Other Postretirement Benefits December 31, 2015 2014 2015 2014 Net actuarial loss $ 10.4 $ 8.1 $ 1.7 $ 3.0 Prior service cost 0.2 0.3 — 0.1 Total $ 10.6 $ 8.4 $ 1.7 $ 3.1 Amounts recognized in regulatory assets were as follows: Millions of Dollars Pension Benefits Other Postretirement Benefits December 31, 2015 2014 2015 2014 Net actuarial loss $ 219.4 $ 222.1 $ 24.0 $ 43.8 Prior service cost 5.9 9.6 0.3 0.6 Total $ 225.3 $ 231.7 $ 24.3 $ 44.4 In connection with the joint ownership of Summer Station, as of December 31, 2015 and 2014, the Company recorded within deferred debits $20.3 million and $17.8 million, respectively, attributable to Santee Cooper’s portion of shared pension costs. As of December 31, 2015 and 2014, the Company also recorded within deferred debits $13.8 million and $15.1 million, respectively, from Santee Cooper, representing its portion of the unfunded postretirement benefit obligation. Changes in Fair Value of Plan Assets Pension Benefits Millions of dollars 2015 2014 Fair value of plan assets, January 1 $ 861.8 $ 870.0 Actual return (loss) on plan assets (16.1 ) 55.8 Benefits paid (64.0 ) (64.0 ) Fair value of plan assets, December 31 $ 781.7 $ 861.8 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. During 2013, in connection with the amendments to the plan, the Company adopted a dynamic investment strategy for the management of the pension plan assets. The 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 Company’s pension plan asset allocation at December 31, 2015 and 2014 and the target allocation for 2016 are as follows: Percentage of Plan Assets Target Allocation December 31, Asset Category 2016 2015 2014 Equity Securities 58 % 57 % 57 % Fixed Income 33 % 32 % 34 % Hedge Funds 9 % 11 % 9 % For 2016, the expected long-term rate of return on assets will be 7.50% . 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 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 as described below. Assets are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. At December 31, 2015 and 2014, fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows: Fair Value Measurements at Reporting Date Using Millions of dollars Total Level 2 Level 3 Total Level 2 Level 3 December 31, 2015 December 31, 2014 Mutual funds $ 538 $ 538 — $ 622 $ 622 — Short-term investment vehicles 14 14 — 20 20 — US Treasury securities 22 22 — 6 6 — Corporate debt securities 78 78 — 86 86 — Municipals 14 14 — 15 15 — Limited partnerships 33 33 — 32 32 — Multi‑strategy hedge funds 83 — $ 83 81 — $ 81 $ 782 $ 699 $ 83 $ 862 $ 781 $ 81 At December 31, 2015, assets with fair value measurements classified as Level 1 were insignificant. There were no transfers of fair value amounts into or out of Levels 1, 2 or 3 during 2015 or 2014. The pension plan values certain mutual funds, where applicable, using unadjusted quoted prices from a national stock exchange, such as NYSE and NASDAQ, where the securities are actively traded. Other mutual funds and limited partnerships are valued using the observable prices of the underlying fund assets based on trade data for identical or similar securities or from a national stock exchange for similar assets or broker quotes. 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. Government agency 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. Hedge funds represent investments in a hedge fund of funds partnership that invests directly in multiple hedge fund strategies that are not traded on exchanges and do not trade on a daily basis. The fair value of this multi-strategy hedge fund is estimated based on the net asset value of the underlying hedge fund strategies using consistent valuation guidelines that account for variations that may impact their fair value. The estimated fair value is the price at which redemptions and subscriptions occur. Fair Value Measurements Level 3 Millions of dollars 2015 2014 Beginning Balance $ 81 $ 76 Unrealized gains included in changes in net assets 2 5 Purchases, issuances, and settlements — — Ending Balance $ 83 $ 81 Expected Cash Flows The total benefits expected to be paid from the pension plan or from the Company’s assets for the other postretirement benefits plan (net of participant contributions), respectively, are as follows: Expected Benefit Payments Millions of dollars Pension Benefits Other Postretirement Benefits 2016 $ 65.1 $ 11.9 2017 63.2 12.7 2018 64.7 13.5 2019 65.3 14.2 2020 65.8 14.9 2021-2025 338.3 80.5 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 in the future, the Company does not anticipate making significant contributions to the pension plan for the foreseeable future. Net Periodic Benefit Cost The Company records net periodic benefit cost utilizing beginning of the year assumptions. Disclosures required for these plans are set forth in the following tables. Components of Net Periodic Benefit Cost Pension Benefits Other Postretirement Benefits Millions of dollars 2015 2014 2013 2015 2014 2013 Service cost $ 24.1 $ 20.0 $ 21.8 $ 5.3 $ 4.6 $ 5.9 Interest cost 38.2 40.4 38.5 11.4 12.0 11.1 Expected return on assets (62.0 ) (66.7 ) (61.4 ) n/a n/a n/a Prior service cost amortization 4.1 4.1 6.0 0.4 0.3 0.7 Amortization of actuarial losses 13.6 4.8 16.9 2.1 — 3.3 Transition obligation amortization — — — — — 0.3 Curtailment — — 9.9 — — — Net periodic benefit cost $ 18.0 $ 2.6 $ 31.7 $ 19.2 $ 16.9 $ 21.3 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: Pension Benefits Other Postretirement Benefits Millions of dollars 2015 2014 2013 2015 2014 2013 Current year actuarial (gain) loss $ 2.7 $ 3.1 $ (5.0 ) $ (1.2 ) $ 1.3 $ (1.8 ) Amortization of actuarial losses (0.4 ) (0.2 ) (0.5 ) (0.1 ) — (0.2 ) Amortization of prior service cost (0.1 ) (0.2 ) (0.2 ) (0.1 ) — — Prior service cost (credit) — — (0.3 ) — — — Amortization of transition obligation — — — — — (0.1 ) Total recognized in OCI $ 2.2 $ 2.7 $ (6.0 ) $ (1.4 ) $ 1.3 $ (2.1 ) Other changes in plan assets and benefit obligations recognized in regulatory assets were as follows: Pension Benefits Other Postretirement Benefits Millions of dollars 2015 2014 2013 2015 2014 2013 Current year actuarial (gain) loss $ 9.2 $ 101.3 $ (157.5 ) $ (18.0 ) $ 19.4 $ (29.9 ) Amortization of actuarial losses (11.9 ) (4.0 ) (14.7 ) (1.8 ) — (2.7 ) Amortization of prior service cost (3.7 ) (3.2 ) (5.2 ) (0.3 ) (0.3 ) (0.6 ) Prior service cost (credit) — — (8.9 ) — — — Amortization of transition obligation — — — — — (0.2 ) Total recognized in regulatory assets $ (6.4 ) $ 94.1 $ (186.3 ) $ (20.1 ) $ 19.1 $ (33.4 ) Significant Assumptions Used in Determining Net Periodic Benefit Cost Pension Benefits Other Postretirement Benefits 2015 2014 2013 2015 2014 2013 Discount rate 4.20 % 5.03 % 4.10%/5.07% 4.30 % 5.19 % 4.19 % Expected return on plan assets 7.50 % 8.00 % 8.00 % n/a n/a n/a Rate of compensation increase 3.00 % 3.00 % 3.75%/3.00% 3.00 % 3.75 % 3.75 % Health care cost trend rate n/a n/a n/a 7.00 % 7.40 % 7.80 % 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 2020 2020 2020 Net periodic benefit cost for the period through September 1, 2013 was determined using a 4.10% discount rate, and net periodic benefit cost after that date was determined using a 5.07% discount rate. Similarly, estimated rates of compensation increase were changed in connection with the September 1, 2013 remeasurement. The estimated amounts to be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2016 are as follows: Millions of Dollars Pension Benefits Other Postretirement Benefits Actuarial loss $ 0.6 — Prior service cost 0.2 — Total $ 0.8 — The estimated amounts to be amortized from regulatory assets into net periodic benefit cost in 2016 are as follows: Millions of Dollars Pension Benefits Other Postretirement Benefits Actuarial loss $ 12.7 $ 0.3 Prior service cost 3.4 0.3 Total $ 16.1 $ 0.6 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 The Company 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. Employee deferrals are fully vested and nonforfeitable at all times. The Company provides 100% matching contributions up to 6% of an employee’s eligible earnings. Total matching contributions made to the plan were $26.2 million in 2015, $25.8 million in 2014 and $23.4 million in 2013 and were made in the form of SCANA common stock.
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 SCE&G participates in SCANA’s noncontributory defined benefit pension plan, which covers regular, full-time employees hired before January 1, 2014. SCANA’s policy has been to fund the plan as permitted by applicable federal income tax regulations, as determined by an independent actuary. SCANA’s pension plan provides benefits under a cash balance formula for employees hired before January 1, 2000 who elected that option and for 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, SCE&G participates in SCANA’s unfunded postretirement health care and life insurance programs which provide benefits to certain active and retired employees. Retirees hired before January 1, 2011 share in a portion of their medical care cost, while employees hired subsequently are responsible for the full costs 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. The information presented below reflects Consolidated SCE&G's portion of the obligations, assets, funded status, net periodic benefit costs, and other information reported for the parent sponsored plans as a whole. The tabular data presented reflects the use of various cost assignment methodologies and participation assumptions based on Consolidated SCE&G's past and current employees and its share of plan assets. 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. Pension Benefits Other Postretirement Benefits Millions of dollars 2015 2014 2015 2014 Benefit obligation, January 1 $ 773.7 $ 695.7 $ 204.1 $ 181.7 Service cost 19.3 16.0 4.4 3.6 Interest cost 32.2 34.1 9.4 9.4 Plan participants’ contributions — — 1.9 1.8 Actuarial (gain) loss (47.0 ) 82.7 (15.7 ) 18.6 Benefits paid (54.2 ) (54.8 ) (10.3 ) (9.6 ) Amounts funded to parent — — (2.1 ) (1.4 ) Benefit obligation, December 31 $ 724.0 $ 773.7 $ 191.7 $ 204.1 SCANA adopted new mortality tables and an improvement scale published by the Society of Actuaries in 2014, resulting in an actuarial loss for pension and other post retirement benefit obligations of approximately $22.1 million and $2.1 million , respectively, in 2014. In 2015, based on an evaluation of the mortality experience of the pension plan, SCANA adopted a custom mortality table 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 of approximately $18.2 million and $2.0 million , respectively, in 2015. The accumulated benefit obligation for pension benefits was $702.0 million at the end of 2015 and $747.6 million at the end of 2014. 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 2015 2014 2015 2014 Annual discount rate used to determine benefit obligation 4.68 % 4.20 % 4.78 % 4.30 % Assumed annual rate of future salary increases for projected benefit obligation 3.00 % 3.00 % 3.00 % 3.00 % A 7.0% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2015. 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 would increase the postretirement benefit obligation by $0.6 million at December 31, 2015 and by $0.9 million at December 31, 2014. A one percent decrease in the assumed health care cost trend rate would decrease the postretirement benefit obligation by $0.6 million at December 31, 2015 and by $0.8 million at December 31, 2014. Funded Status Millions of Dollars Pension Benefits Other Postretirement Benefits December 31, 2015 2014 2015 2014 Fair value of plan assets $ 720.1 $ 783.6 — — Benefit obligation 724.0 773.7 $ 191.7 $ 204.1 Funded status $ (3.9 ) $ 9.9 $ (191.7 ) $ (204.1 ) Amounts recognized on the consolidated balance sheets were as follows: Millions of Dollars Pension Benefits Other Postretirement Benefits December 31, 2015 2014 2015 2014 Current liability — — $ (9.8 ) $ (8.5 ) Noncurrent asset — $ 9.9 — — Noncurrent liability $ (3.9 ) — (181.9 ) (195.6 ) Amounts recognized in accumulated other comprehensive loss were as follows: Millions of Dollars Pension Benefits Other Postretirement Benefits December 31, 2015 2014 2015 2014 Net actuarial loss $ 2.0 $ 1.9 $ 0.7 $ 1.0 Prior service cost — 0.1 — — Total $ 2.0 $ 2.0 $ 0.7 $ 1.0 Amounts recognized in regulatory assets were as follows: Millions of Dollars Pension Benefits Other Postretirement Benefits December 31, 2015 2014 2015 2014 Net actuarial loss $ 193.7 $ 191.9 $ 20.4 $ 35.9 Prior service cost 5.2 8.3 0.2 0.5 Total $ 198.9 $ 200.2 $ 20.6 $ 36.4 In connection with the joint ownership of Summer Station, as of December 31, 2015 and 2014, SCE&G recorded within deferred debits $20.3 million and $17.8 million, respectively, attributable to Santee Cooper’s portion of shared pension costs. As of December 31, 2015 and 2014, SCE&G also recorded within deferred debits $13.8 million and $15.1 million, respectively, from Santee Cooper, representing its portion of the unfunded postretirement benefit obligation. Changes in Fair Value of Plan Assets Pension Benefits Millions of dollars 2015 2014 Fair value of plan assets, January 1 $ 783.6 $ 792.1 Actual return (loss) on plan assets (9.3 ) 46.3 Benefits paid (54.2 ) (54.8 ) Fair value of plan assets, December 31 $ 720.1 $ 783.6 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. During 2013, in connection with the amendments to the plan, SCANA adopted a dynamic investment strategy for the management of the pension plan assets. The 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, 2015 and 2014 and the target allocation for 2016 are as follows: Percentage of Plan Assets Target Allocation December 31, Asset Category 2016 2015 2014 Equity Securities 58 % 57 % 57 % Fixed Income 33 % 32 % 34 % Hedge Funds 9 % 11 % 9 % For 2016, the expected long-term rate of return on assets will be 7.50% . 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 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 as described below. Assets are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. At December 31, 2015 and 2014, fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows: Fair Value Measurements at Reporting Date Using Millions of dollars Total Level 2 Level 3 Total Level 2 Level 3 December 31, 2015 December 31, 2014 Mutual funds $ 496 $ 496 — $ 566 $ 566 — Short-term investment vehicles 12 12 — 18 18 — US Treasury securities 20 20 — 6 6 — Corporate debt securities 72 72 — 78 78 — Municipals 13 13 — 14 14 — Limited partnerships 30 30 — 29 29 — Multi-strategy hedge funds 77 — $ 77 73 — $ 73 $ 720 $ 643 $ 77 $ 784 $ 711 $ 73 At December 31, 2015, assets with fair value measurements classified as Level 1 were insignificant. There were no transfers of fair value amounts into or out of Levels 1, 2 or 3 during 2015 or 2014. The pension plan values certain mutual funds, where applicable, using unadjusted quoted prices from a national stock exchange, such as NYSE and NASDAQ, where the securities are actively traded. Other mutual funds and limited partnerships are valued using the observable prices of the underlying fund assets based on trade data for identical or similar securities or from a national stock exchange for similar assets or broker quotes. 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. Government agency 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. Hedge funds represent investments in a hedge fund of funds partnership that invests directly in multiple hedge fund strategies that are not traded on exchanges and do not trade on a daily basis. The fair value of this multi-strategy hedge fund is estimated based on the net asset value of the underlying hedge fund strategies using consistent valuation guidelines that account for variations that may impact their fair value. The estimated fair value is the price at which redemptions and subscriptions occur. Fair Value Measurements Level 3 Millions of dollars 2015 2014 Beginning Balance $ 73 $ 69 Unrealized gains included in changes in net assets 4 4 Purchases, issuances, and settlements — — Ending Balance $ 77 $ 73 Expected Cash Flows The total benefits expected to be paid from the pension plan or from Consolidated SCE&G’s assets for the other postretirement benefits plan (net of participant contributions), respectively, are as follows: Expected Benefit Payments Millions of dollars Pension Benefits Other Postretirement Benefits 2016 $ 65.1 $ 9.8 2017 63.2 10.5 2018 64.7 11.1 2019 65.3 11.7 2020 65.8 12.3 2021 - 2025 338.3 66.1 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 in the future, SCE&G does not anticipate making significant contributions to the pension plan for the foreseeable future. Net Periodic Benefit Cost Consolidated SCE&G records net periodic benefit cost utilizing beginning of the year assumptions. Disclosures required for these plans are set forth in the following tables. Components of Net Periodic Benefit Cost Pension Benefits Other Postretirement Benefits Millions of dollars 2015 2014 2013 2015 2014 2013 Service cost $ 19.3 $ 16.0 $ 17.6 $ 4.4 $ 3.6 $ 4.6 Interest cost 32.2 34.1 32.6 9.4 9.4 8.7 Expected return on assets (52.2 ) (56.3 ) (51.9 ) n/a n/a n/a Prior service cost amortization 3.4 3.5 5.0 0.3 0.3 0.6 Amortization of actuarial losses 11.4 4.0 14.3 1.7 — 2.6 Curtailment — — 8.4 — — — Net periodic benefit cost $ 14.1 $ 1.3 $ 26.0 $ 15.8 $ 13.3 $ 16.5 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: Pension Benefits Other Postretirement Benefits Millions of dollars 2015 2014 2013 2015 2014 2013 Current year actuarial (gain) loss $ 0.2 $ 0.2 $ (0.8 ) $ (0.3 ) $ 0.4 $ (0.4 ) Amortization of actuarial losses (0.1 ) (0.1 ) (0.1 ) — — (0.1 ) Amortization of prior service cost (0.1 ) (0.1 ) — — — — Total recognized in OCI $ — $ — $ (0.9 ) $ (0.3 ) $ 0.4 $ (0.5 ) Other changes in plan assets and benefit obligations recognized in regulatory assets were as follows: Pension Benefits Other Postretirement Benefits Millions of dollars 2015 2014 2013 2015 2014 2013 Current year actuarial (gain) loss $ 12.2 $ 87.7 $ (137.1 ) $ (14.0 ) $ 15.8 $ (24.4 ) Amortization of actuarial losses (10.4 ) (3.5 ) (12.7 ) (1.5 ) — (2.2 ) Amortization of prior service cost (3.1 ) (2.8 ) (4.5 ) (0.3 ) (0.2 ) (0.5 ) Prior service cost (credit) — — (7.7 ) — — — Amortization of transition obligation — — — — — (0.1 ) Total recognized in regulatory assets $ (1.3 ) $ 81.4 $ (162.0 ) $ (15.8 ) $ 15.6 $ (27.2 ) Significant Assumptions Used in Determining Net Periodic Benefit Cost Pension Benefits Other Postretirement Benefits 2015 2014 2013 2015 2014 2013 Discount rate 4.20 % 5.03 % 4.10%/5.07% 4.30 % 5.19 % 4.19 % Expected return on plan assets 7.50 % 8.00 % 8.00 % n/a n/a n/a Rate of compensation increase 3.00 % 3.00 % 3.75%/3.00% 3.00 % 3.75 % 3.75 % Health care cost trend rate n/a n/a n/a 7.00 % 7.40 % 7.80 % 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 2020 2020 2020 Net periodic benefit cost for the period through September 1, 2013, was determined using a 4.10% discount rate, and net periodic benefit cost after that date was determined using a 5.07% discount rate. Similarly, estimated rates of compensation increase were changed in connection with the September 1, 2013 remeasurement. The actuarial loss and prior service cost to be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2016 are insignificant . The estimated amounts to be amortized from regulatory assets into net periodic benefit cost in 2016 are as follows: Millions of Dollars Pension Benefits Other Postretirement Benefits Actuarial loss $ 11.2 $ 0.3 Prior service cost 3.0 0.2 Total $ 14.2 $ 0.5 Other postretirement benefit costs are subject to annual per capita limits pursuant to the plan's design. As a result, the effect of a one-percent increase or decrease in the assumed health care cost trend rate on total service and interest cost is not significant. 401(k) Retirement Savings Plan SCE&G participates in a SCANA-sponsored defined contribution plan in which eligible employees may defer up to 75% of eligible earnings subject to certain limits and may diversify their investments. Employee deferrals are fully vested and nonforfeitable at all times. SCE&G provides 100% matching contributions up to 6% of an employee’s eligible earnings. Total matching contributions made to the plan were $21.8 million in 2015, $20.7 million in 2014 and $18.7 million in 2013 and were made in the form of SCANA common stock.

SHARE-BASED COMPENSATION

SHARE-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2015
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 2013-2015 and 2014-2016 performance cycles provide 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 award is based on performance over a single three -year cycle. In each performance cycle of the 2013-2015 and 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 the 2015-2017 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. Awards under the 2013-2015 performance cycle were paid in cash totaling $ 18.4 million at SCANA’s discretion in February 2016. Cash-settled liabilities related to earlier performance cycles totaled approximately $ 20.8 million in 2015, $ 11.8 million in 2014, and $ 12.2 million in 2013. Fair value adjustments for all performance cycles resulted in compensation expense recognized in the statements of income totaling approximately $ 18.0 million in 2015, $ 20.3 million in 2014 and $ 8.7 million in 2013. Such fair value adjustments also resulted in capitalized compensation costs of $ 2.3 million in 2015, $ 3.1 million in 2014 and $ 1.4 million in 2013. At December 31, 2015, SCANA had $ 20.4 million of unrecognized compensation cost, which is expected to be recognized over a weighted-average period of 18 months .
SCE&G
Share-Based Compensation
Disclosure of Compensation Related Costs, Share-based Payments [Text Block]	SHARE-BASED COMPENSATION SCE&G participates in the LTECP which 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 2013-2015 and 2014-2016 performance cycles provide 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 award is based on performance over a single three -year cycle. In each performance cycle of the 2013-2015 and 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 the 2015-2017 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. Awards under the 2013-2015 performance cycle were paid in cash totaling $ 3.7 million at SCANA’s discretion in February 2016. Cash-settled liabilities related to earlier performance cycles totaled approximately $ 6.3 million in 2015, $ 1.9 million in 2014 and $ 3.2 million in 2013. Fair value adjustments for all performance cycles resulted in compensation expense recognized in the statements of income totaling approximately $ 12.2 million in 2015, $ 12.6 million in 2014 and $ 5.5 million in 2013. Such fair value adjustments also resulted in capitalized compensation costs of $ 0.6 million in 2015, $ 0.6 million in 2014 and $ 0.5 million in 2013. At December 31, 2015 SCE&G's unrecognized compensation cost was insignificant.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2015
Commitment [Line Items]
Commitments and Contingencies Disclosure [Text Block]	COMMITMENTS AND CONTINGENCIES Nuclear Insurance Under Price-Anderson, SCE&G (for itself and on behalf of Santee-Cooper, a one-third owner of Summer Station 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 the company’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 Summer Station 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 Summer Station Unit 1 for property damage and outage costs up to $2.75 billion resulting from an event of 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 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 premiums, SCE&G’s portion of the retrospective premium assessment would not exceed $43.5 million . To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from a nuclear incident at Summer Station 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 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 incident. However, if such an incident were to occur, it likely would have a material impact on the Company’s results of operations, cash flows and financial position. New Nuclear Construction In 2008, SCE&G, on behalf of itself and as agent for Santee Cooper, contracted with the Consortium for the design and construction of the New Units at the site of Summer Station. 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. Such annual rate changes are described in Note 2. As of December 31, 2015, SCE&G’s investment in the New Units, including related transmission, totaled $3.6 billion , for which the financing costs on $3.2 billion have been reflected in rates 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. In November 2012, the SCPSC approved an updated milestone schedule and additional updated capital costs for the New Units. In addition, the SCPSC approved revised substantial completion dates for the New Units based on that March 2012 issuance of the COL and the amounts agreed upon by SCE&G and the Consortium in July 2012 to resolve known claims by the Consortium for costs related to COL delays, design modifications of the shield building and certain prefabricated structural modules for the New Units and unanticipated rock conditions at the site. In October 2014, the South Carolina Supreme Court affirmed the SCPSC's order on appeal. Since the settlement of delay-related claims in 2012, the Consortium has continued to experience delays in the schedule. Shield building construction remains a principal focus area for SCE&G’s oversight of the project. The primary critical path for both Unit 2 and Unit 3 runs through the placement of concrete within the containment vessels, the fabrication of shield building panels, the fabrication of the air inlet and tension rings and the completion of shield building construction. For Unit 3, the critical path also runs through the setting of CA20 which is a prerequisite to concrete placement in certain areas of the nuclear island. Plans to accelerate the work needed to permit placing this concrete are underway. In addition, WEC has reached agreement on a mitigation plan to accelerate shield building panel fabrication with one of its subcontractors. Additional mitigation will be required in critical path areas to support the updated substantial completion dates described below. During the fourth quarter of 2013, the Consortium began a full re-baselining of the Unit 2 and Unit 3 construction schedules to incorporate a more detailed evaluation of the engineering and procurement activities necessary to accomplish the schedules and to provide a detailed reassessment of the impact of the revised Unit 2 and Unit 3 schedules on engineering and design resource allocations, procurement, construction work crew efficiencies, and other items. The result was a revised fully integrated project schedule with timing of specific construction activities (Revised, Fully-Integrated Construction Schedule) along with related cost information. The Revised, Fully-Integrated Construction Schedule indicated that the substantial completion of Unit 2 was expected to occur in mid-June 2019 and that the substantial completion of Unit 3 was expected to be approximately 12 months later. The Consortium continues to refine and update the Revised, Fully-Integrated Construction Schedule as designs are finalized, as construction progresses, and as additional information is received. In September 2015, the SCPSC approved an updated BLRA milestone schedule based on revised substantial completion dates for Units 2 and 3 of June 2019 and June 2020, respectively, each subject to an 18-month contingency period. In addition, the SCPSC approved certain updated owner's costs ( $245 million ) and other capital costs ( $453 million ), of which $539 million were associated with the schedule delays and other contested costs. In this proceeding, SCE&G's total projected capital costs (in 2007 dollars) and gross construction cost estimates (including escalation and AFC) were estimated to be $5.2 billion and $6.8 billion , respectively. These projections included cost amounts related to the Revised, Fully-Integrated Construction Schedule for which SCE&G had not accepted responsibility and which were the subject of dispute. As such, these updated milestone schedule and projections did not reflect the resolution of negotiations. In addition, the SCPSC approved a revision to the allowed return on equity for new nuclear construction from 11.0% to 10.5%. This revised return on equity will be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2016, until such time as the New Units are completed. On October 27, 2015, SCE&G, Santee Cooper and the Consortium reached a settlement regarding the above mentioned disputes, and the EPC Contract was amended. 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 Corporation as a subcontracted construction manager. Among other things, the October 2015 Amendment: (i) resolved by settlement and release substantially all outstanding disputes between SCE&G and the Consortium, in exchange for (a) an additional cost to be paid by SCE&G and Santee Cooper of $300 million (SCE&G’s 55% portion being $165 million ) and an increase in the fixed component of the contract price by that amount, and (b) a credit to SCE&G and Santee Cooper of $50 million (SCE&G’s 55% portion being approximately $27 million ) to be applied to the target component of the contract price, (ii) revised the 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), and capped those aggregate liquidated damages at $463 million per New Unit (SCE&G’s 55% portion being approximately $255 million per New Unit), (iv) provides for payment to the Consortium of a completion bonus of $275 million per New Unit (SCE&G’s 55% portion being approximately $151 million per New Unit) for each New Unit placed in service by the deadline to qualify for production tax credits, (v) provides for development of a revised construction milestone payment schedule, with SCE&G and Santee Cooper making monthly payments of $100 million (SCE&G’s 55% portion being $55 million ) for each of the first five months following effectiveness, followed by payments made based on milestones achieved, and (vi) provided that SCE&G and Santee Cooper waive and cancel the CB&I parent company guaranty with respect to the project. Under the October 2015 Amendment, SCE&G’s total estimated project costs increased by approximately $286 million over the $6.8 billion approved by the SCPSC in September 2015, bringing its total estimated gross construction cost of the project (including escalation and AFC) to approximately $7.1 billion . The payment obligations under the EPC Contract are joint and several obligations of WEC and Stone & Webster, and in connection with the October 2015 Amendment, Toshiba Corporation, WEC’s parent company, reaffirmed its guaranty of WEC’s payment obligations. Based on Toshiba's current credit ratings and pursuant to the terms of the EPC Contract, SCE&G has exercised its rights to demand a payment and performance bond from WEC. Such bond will be based on estimated billings and its aggregate nominal coverage will not exceed $100 million (or $55 million for SCE&G's 55% share). SCE&G and Santee Cooper are responsible for the cost of the bond. In addition, the EPC Contract provides that upon the request of SCE&G, the Consortium must escrow certain intellectual property and software for SCE&G's benefit to enable completion of the New Units. SCE&G has made such a request to the Consortium. In addition to the above, the October 2015 Amendment provided for an explicit definition of a Change in Law designed to reduce the likelihood of certain future commercial disputes, and the Consortium also acknowledged and agreed that the project scope includes providing New Units that meet the standards of the NRC approved Design Control Document Revision 19. The October 2015 Amendment also established a dispute resolution board process for certain commercial claims and disputes, including any dispute that might arise with respect to the development of the revised construction milestone payment schedule referred to above. The EPC Contract was also revised to eliminate the requirement or ability to bring suit before substantial completion of the project. Finally, the October 2015 Amendment provides SCE&G and Santee Cooper an irrevocable option, until November 1, 2016 and subject to regulatory approvals, to further amend the EPC Contract 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 subject to adjustment for amounts paid since June 30, 2015. Were this fixed price option to be exercised, the aggregate delay-related liquidated damages referred to in (iii) above would be capped at $338 million per unit (SCE&G’s 55% portion being approximately $186 million per unit), and the completion bonus referred to in (iv) above would be $150 million per New Unit (SCE&G’s 55% portion being approximately $83 million per New Unit). The exercise of this fixed price option would result in SCE&G’s total estimated project costs increasing by approximately $774 million over the $6.8 billion approved by the SCPSC in September 2015, and would bring its total estimated gross construction cost (including escalation and AFC) of the project to approximately $7.6 billion . Resolution of the disputes as described in (i) above, or in the case of the exercise of the fixed price option, would result in estimated project costs above the amounts approved by the SCPSC; however, the guaranteed substantial completion dates fall within the SCPSC approved 18-month contingency periods. SCE&G held an allowable ex parte communication briefing with the SCPSC on November 19, 2015 and, following an evaluation as to whether to exercise the fixed price option, expects to file a petition in 2016, as provided under the BLRA, for an update to the project’s estimated capital cost and milestone schedule which would incorporate the impact of the October 2015 Amendment. Additional claims by the Consortium or SCE&G involving the project schedule and budget 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. SCE&G expects to resolve all disputes through both the informal and formal procedures and currently anticipates that any costs that arise through such dispute resolution processes (including those reflected in the October 2015 Amendment described above), as well as other costs identified from time to time, will be recoverable through rates. 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 will not affect the payment obligations between the parties during construction for 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. Based on the October 2015 Amendment, which has not been approved by the SCPSC, SCE&G’s currently projected cost would be approximately $750 million to $850 million for the additional 5% interest being acquired from Santee Cooper. 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 Internal Revenue Code 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 the guaranteed substantial completion dates provided above, both New Units are expected to be operational and to qualify for the nuclear production tax credits; however, further delays in the schedule or changes in tax law could impact such conclusions. 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 is currently 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 financial condition, results of operations and cash flows. In addition, the Company 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 expects 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 sulfur dioxide and nitrogen oxide 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 carbon dioxide 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 carbon dioxide per MWh and new natural gas units to meet 1,000 pounds carbon dioxide 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 is evaluating the final rule, but does 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 carbon dioxide 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 states 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. It is expected that South Carolina will request a two-year extension (until September 2018). 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 is currently evaluating the rule and expects 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 sulfur dioxide and nitrogen oxide from power plants in the eastern half of the United States. A series of court actions stayed this rule until October 23, 2014, when the Court of Appeals granted a motion to lift the stay. On December 3, 2014, the EPA published an interim final rule that aligns the dates in the CSAPR text with the revised court-ordered schedule, which delayed the implementation dates to 2015 for Phase 1 and to 2017 for Phase 2. The CSAPR replaces the CAIR and requires a total of 28 states to reduce annual sulfur dioxide emissions and annual or ozone season nitrogen oxide emissions to assist in attaining the ozone and fine particle NAAQS. The rule establishes an emissions cap for sulfur dioxide and nitrogen oxide and limits the trading for emission allowances by separating affected states into two groups with no trading between the groups. On July 28, 2015, the Court of Appeals held that Phase 2 emissions budgets for certain states, including South Carolina, required reductions in emissions beyond the point necessary to achieve downwind attainment and were, therefore, invalid. The Court of Appeals remanded CSAPR, without vacating the rule, to the EPA for further consideration. The opinion of the Court of Appeals has no immediate impact on SCE&G and GENCO or their generation operations. 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 cost 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 rule provides up to four years for generating facilities to meet the standards, and the Company's evaluation of the rule is ongoing. The Company's decision to retire certain coal-fired units (see Note 2) and its project to build the New Units along with other actions are expected to result in the Company's compliance with MATS. On November 19, 2014, the EPA finalized its reconsideration of certain provisions applicable during startup and shutdown of generating facilities under the MATS rule. SCE&G and GENCO have received a one year extension (until April 2016) to comply with MATS at Cope, McMeekin, Wateree and Williams Stations. These extensions will allow time to convert McMeekin Station to burn natural gas and to install additional pollution control devices at the other plants that will enhance the control of certain MATS-regulated pollutants. On June 29, 2015, the U.S. Supreme Court ruled that the EPA unreasonably failed to consider costs in its decision to regulate, and remanded a case challenging the regulation on that basis to the Court of Appeals. The Court noted during remand that EPA has said that it is on track to issue a revised "appropriate and necessary" finding by April 15, 2016. The ruling, however, is not expected to have an impact on SCE&G or GENCO due to the aforementioned retirements and conversions. SCE&G and GENCO currently 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 expects that wastewater treatment technology retrofits will be required at Williams and Wateree Stations and may be required at other facilities. 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 to ensure compliance with this rule. In addition, Congress is expected to consider further amendments to the CWA. Such legislation may include toxicity-based standards as well as limitations to mixing zones. On April 17, 2015, the EPA's final rule for CCR was published in the Federal Register and 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. Although the full effects of this rule are still being evaluated, 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 does not expect the incremental compliance costs associated with this rule to be significant and expects 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, 2015, the federal government has not accepted any spent fuel from Summer Station Unit 1, and it remains unclear when the repository may become available. SCE&G has on-site spent nuclear fuel storage capability in its existing fuel pool until at least 2017 and has constructed a dry cask storage facility to accommodate the spent nuclear fuel output for the life of Summer Station 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 through 2017 and will cost an additional $18.5 million , which is accrued in Other within Deferred Credits and Other Liabilities on the consolidated balance sheet. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates. At December 31, 2015, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $34.8 million and are included in regulatory assets. Claims and Litigation The Company is subject to various claims and litigation incidental to its business operations which management anticipates will be resolved without a material impact on the Company’s results of operations, cash flows or financial condition. Operating Lease Commitments The Company is obligated under various operating leases for rail cars, vehicles, office space, furniture and equipment. Leases expire at various dates through 2051. Rent expense totaled approximately $ 11.1 million in 2015, $ 12.3 million in 2014 and $ 14.8 million in 2013. Future minimum rental payments under such leases will be $10 million in 2016, $7 million in 2017, $6 million in 2018, $6 million in 2019, $3 million in 2020 and $27 million thereafter. Guarantees SCANA issues guarantees on behalf of its consolidated subsidiaries to facilitate commercial transactions with third parties. These guarantees are in the form of performance guarantees, primarily for the purchase and transportation of natural gas, standby letters of credit issued by financial institutions and credit support for certain tax-exempt bond issues. SCANA is not required to recognize a liability for such guarantees unless it becomes probable that performance under the guarantees will be required. SCANA believes the likelihood that it would be required to perform or otherwise incur any losses associated with these guarantees is remote; therefore, no liability for these guarantees has been recognized. To the extent that a liability subject to a guarantee has been incurred, the liability is included in the consolidated financial statements. At December 31, 2015, the maximum future payments (undiscounted) that SCANA could be required to make under guarantees totaled approximately $1.8 billion . Asset Retirement Obligations The Company recognizes a liability for the present value of an ARO when incurred if the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional ARO is factored into the measurement of the liability when sufficient information exists, but such uncertainty is not a basis upon which to avoid liability recognition. The
SCE&G
Commitment [Line Items]
Commitments and Contingencies Disclosure [Text Block]	COMMITMENTS AND CONTINGENCIES Nuclear Insurance Under Price-Anderson, SCE&G (for itself and on behalf of Santee-Cooper, a one-third owner of Summer Station 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 the company’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 Summer Station 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 Summer Station Unit 1 for property damage and outage costs up to $2.75 billion resulting from an event of 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 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 premiums, SCE&G’s portion of the retrospective premium assessment would not exceed $43.5 million . To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from a nuclear incident at Summer Station 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 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 incident. However, if such an incident were to occur, it likely would have a material impact on the Consolidated SCE&G’s results of operations, cash flows and financial position. New Nuclear Construction In 2008, SCE&G, on behalf of itself and as agent for Santee Cooper, contracted with the Consortium for the design and construction of the New Units at the site of Summer Station. 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. Such annual rate changes are described in Note 2. As of December 31, 2015, SCE&G’s investment in the New Units, including related transmission, totaled $3.6 billion , for which the financing costs on $3.2 billion have been reflected in rates 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. In November 2012, the SCPSC approved an updated milestone schedule and additional updated capital costs for the New Units. In addition, the SCPSC approved revised substantial completion dates for the New Units based on that March 2012 issuance of the COL and the amounts agreed upon by SCE&G and the Consortium in July 2012 to resolve known claims by the Consortium for costs related to COL delays, design modifications of the shield building and certain prefabricated structural modules for the New Units and unanticipated rock conditions at the site. In October 2014, the South Carolina Supreme Court affirmed the SCPSC's order on appeal. Since the settlement of delay-related claims in 2012, the Consortium has continued to experience delays in the schedule. Shield building construction remains a principal focus area for SCE&G’s oversight of the project. The primary critical path for both Unit 2 and Unit 3 runs through the placement of concrete within the containment vessels, the fabrication of shield building panels, the fabrication of the air inlet and tension rings and the completion of shield building construction. For Unit 3, the critical path also runs through the setting of CA20 which is a prerequisite to concrete placement in certain areas of the nuclear island. Plans to accelerate the work needed to permit placing this concrete are underway. In addition, WEC has reached agreement on a mitigation plan to accelerate shield building panel fabrication with one of its subcontractors. Additional mitigation will be required in critical path areas to support the updated substantial completion dates described below. During the fourth quarter of 2013, the Consortium began a full re-baselining of the Unit 2 and Unit 3 construction schedules to incorporate a more detailed evaluation of the engineering and procurement activities necessary to accomplish the schedules and to provide a detailed reassessment of the impact of the revised Unit 2 and Unit 3 schedules on engineering and design resource allocations, procurement, construction work crew efficiencies, and other items. The result was a revised fully integrated project schedule with timing of specific construction activities (Revised, Fully-Integrated Construction Schedule) along with related cost information. The Revised, Fully-Integrated Construction Schedule indicated that the substantial completion of Unit 2 was expected to occur in mid-June 2019 and that the substantial completion of Unit 3 was expected to be approximately 12 months later. The Consortium continues to refine and update the Revised, Fully-Integrated Construction Schedule as designs are finalized, as construction progresses, and as additional information is received. In September 2015, the SCPSC approved an updated BLRA milestone schedule based on revised substantial completion dates for Units 2 and 3 of June 2019 and June 2020, respectively, each subject to an 18-month contingency period. In addition, the SCPSC approved certain updated owner's costs ( $245 million ) and other capital costs ( $453 million ), of which $539 million were associated with the schedule delays and other contested costs. In this proceeding, SCE&G's total projected capital costs (in 2007 dollars) and gross construction cost estimates (including escalation and AFC) were estimated to be $5.2 billion and $6.8 billion , respectively. These projections included cost amounts related to the Revised, Fully-Integrated Construction Schedule for which SCE&G had not accepted responsibility and which were the subject of dispute. As such, these updated milestone schedule and projections did not reflect the resolution of negotiations. In addition, the SCPSC approved a revision to the allowed return on equity for new nuclear construction from 11.0% to 10.5%. This revised return on equity will be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2016, until such time as the New Units are completed. On October 27, 2015, SCE&G, Santee Cooper and the Consortium reached a settlement regarding the above mentioned disputes, and the EPC Contract was amended. 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 Corporation as a subcontracted construction manager. Among other things, the October 2015 Amendment: (i) resolved by settlement and release substantially all outstanding disputes between SCE&G and the Consortium, in exchange for (a) an additional cost to be paid by SCE&G and Santee Cooper of $300 million (SCE&G’s 55% portion being $165 million ) and an increase in the fixed component of the contract price by that amount, and (b) a credit to SCE&G and Santee Cooper of $50 million (SCE&G’s 55% portion being approximately $27 million ) to be applied to the target component of the contract price, (ii) revised the 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), and capped those aggregate liquidated damages at $463 million per New Unit (SCE&G’s 55% portion being approximately $255 million per New Unit), (iv) provides for payment to the Consortium of a completion bonus of $275 million per New Unit (SCE&G’s 55% portion being approximately $151 million per New Unit) for each New Unit placed in service by the deadline to qualify for production tax credits, (v) provides for development of a revised construction milestone payment schedule, with SCE&G and Santee Cooper making monthly payments of $100 million (SCE&G’s 55% portion being $55 million ) for each of the first five months following effectiveness, followed by payments made based on milestones achieved, and (vi) provided that SCE&G and Santee Cooper waive and cancel the CB&I parent company guaranty with respect to the project. Under the October 2015 Amendment, SCE&G’s total estimated project costs increased by approximately $286 million over the $6.8 billion approved by the SCPSC in September 2015, bringing its total estimated gross construction cost of the project (including escalation and AFC) to approximately $7.1 billion . The payment obligations under the EPC Contract are joint and several obligations of WEC and Stone & Webster, and in connection with the October 2015 Amendment, Toshiba Corporation, WEC’s parent company, reaffirmed its guaranty of WEC’s payment obligations. Based on Toshiba's current credit ratings and pursuant to the terms of the EPC Contract, SCE&G has exercised its rights to demand a payment and performance bond from WEC. Such bond will be based on estimated billings and its aggregate nominal coverage will not exceed $100 million (or $55 million for SCE&G's 55% share). SCE&G and Santee Cooper are responsible for the cost of the bond. In addition, the EPC Contract provides that upon the request of SCE&G, the Consortium must escrow certain intellectual property and software for SCE&G's benefit to enable completion of the New Units. SCE&G has made such a request to the Consortium. In addition to the above, the October 2015 Amendment provided for an explicit definition of a Change in Law designed to reduce the likelihood of certain future commercial disputes, and the Consortium also acknowledged and agreed that the project scope includes providing New Units that meet the standards of the NRC approved Design Control Document Revision 19. The October 2015 Amendment also established a dispute resolution board process for certain commercial claims and disputes, including any dispute that might arise with respect to the development of the revised construction milestone payment schedule referred to above. The EPC Contract was also revised to eliminate the requirement or ability to bring suit before substantial completion of the project. Finally, the October 2015 Amendment provides SCE&G and Santee Cooper an irrevocable option, until November 1, 2016 and subject to regulatory approvals, to further amend the EPC Contract 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 subject to adjustment for amounts paid since June 30, 2015. Were this fixed price option to be exercised, the aggregate delay-related liquidated damages referred to in (iii) above would be capped at $338 million per unit (SCE&G’s 55% portion being approximately $186 million per unit), and the completion bonus referred to in (iv) above would be $150 million per New Unit (SCE&G’s 55% portion being approximately $83 million per New Unit). The exercise of this fixed price option would result in SCE&G’s total estimated project costs increasing by approximately $774 million over the $6.8 billion approved by the SCPSC in September 2015, and would bring its total estimated gross construction cost (including escalation and AFC) of the project to approximately $7.6 billion . Resolution of the disputes as described in (i) above, or in the case of the exercise of the fixed price option, would result in estimated project costs above the amounts approved by the SCPSC; however, the guaranteed substantial completion dates fall within the SCPSC approved 18-month contingency periods. SCE&G held an allowable ex parte communication briefing with the SCPSC on November 19, 2015 and, following an evaluation as to whether to exercise the fixed price option, expects to file a petition in 2016, as provided under the BLRA, for an update to the project’s estimated capital cost and milestone schedule which would incorporate the impact of the October 2015 Amendment. Additional claims by the Consortium or SCE&G involving the project schedule and budget 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. SCE&G expects to resolve all disputes through both the informal and formal procedures and currently anticipates that any costs that arise through such dispute resolution processes (including those reflected in the October 2015 Amendment described above), as well as other costs identified from time to time, will be recoverable through rates. 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 will not affect the payment obligations between the parties during construction for 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. Based on the October 2015 Amendment, which has not been approved by the SCPSC, SCE&G’s currently projected cost would be approximately $750 million to $850 million for the additional 5% interest being acquired from Santee Cooper. 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 Internal Revenue Code 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 the guaranteed substantial completion dates provided above, both New Units are expected to be operational and to qualify for the nuclear production tax credits; however, further delays in the schedule or changes in tax law could impact such conclusions. 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 is currently 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 Consolidated SCE&G'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 Consolidated SCE&G's financial condition, results of operations and cash flows. In addition, 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, Consolidated SCE&G expects to recover such expenditures and costs through existing ratemaking provisions. From a regulatory perspective, 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 sulfur dioxide and nitrogen oxide 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 carbon dioxide 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 carbon dioxide per MWh and new natural gas units to meet 1,000 pounds carbon dioxide 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. Consolidated SCE&G is evaluating the final rule, but does 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 carbon dioxide 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 states 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. It is expected that South Carolina will request a two-year extension (until September 2018). 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. Consolidated SCE&G is currently evaluating the rule and expects 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 sulfur dioxide and nitrogen oxide from power plants in the eastern half of the United States. A series of court actions stayed this rule until October 23, 2014, when the Court of Appeals granted a motion to lift the stay. On December 3, 2014, the EPA published an interim final rule that aligns the dates in the CSAPR text with the revised court-ordered schedule, which delayed the implementation dates to 2015 for Phase 1 and to 2017 for Phase 2. The CSAPR replaces the CAIR and requires a total of 28 states to reduce annual sulfur dioxide emissions and annual or ozone season nitrogen oxide emissions to assist in attaining the ozone and fine particle NAAQS. The rule establishes an emissions cap for sulfur dioxide and nitrogen oxide and limits the trading for emission allowances by separating affected states into two groups with no trading between the groups. On July 28, 2015, the Court of Appeals held that Phase 2 emissions budgets for certain states, including South Carolina, required reductions in emissions beyond the point necessary to achieve downwind attainment and were, therefore, invalid. The Court of Appeals remanded CSAPR, without vacating the rule, to the EPA for further consideration. The opinion of the Court of Appeals has no immediate impact on SCE&G and GENCO or their generation operations. 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 cost 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 rule provides up to four years for generating facilities to meet the standards, and SCE&G and GENCO's evaluation of the rule is ongoing. SCE&G's decision to retire certain coal-fired units (see Note 2) and its project to build the New Units along with other actions are expected to result in the SCE&G's compliance with MATS. On November 19, 2014, the EPA finalized its reconsideration of certain provisions applicable during startup and shutdown of generating facilities under the MATS rule. SCE&G and GENCO have received a one year extension (until April 2016) to comply with MATS at Cope, McMeekin, Wateree and Williams Stations. These extensions will allow time to convert McMeekin Station to burn natural gas and to install additional pollution control devices at the other plants that will enhance the control of certain MATS-regulated pollutants. On June 29, 2015, the U.S. Supreme Court ruled that the EPA unreasonably failed to consider costs in its decision to regulate, and remanded a case challenging the regulation on that basis to the Court of Appeals. The Court noted during remand that EPA has said that it is on track to issue a revised "appropriate and necessary" finding by April 15, 2016. The ruling, however, is not expected to have an impact on SCE&G or GENCO due to the aforementioned retirements and conversions. SCE&G and GENCO currently 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. Consolidated SCE&G expects that wastewater treatment technology retrofits will be required at Williams and Wateree Stations and may be required at other facilities. 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 to ensure compliance with this rule. In addition, Congress is expected to consider further amendments to the CWA. Such legislation may include toxicity-based standards as well as limitations to mixing zones. On April 17, 2015, the EPA's final rule for CCR was published in the Federal Register and 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. Although the full effects of this rule are still being evaluated, 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. Consolidated SCE&G does not expect the incremental compliance costs associated with this rule to be significant and expects 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, 2015, the federal government has not accepted any spent fuel from Summer Station Unit 1, and it remains unclear when the repository may become available. SCE&G has on-site spent nuclear fuel storage capability in its existing fuel pool until at least 2017 and has constructed a dry cask storage facility to accommodate the spent nuclear fuel output for the life of Summer Station 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 state of South Carolina has similar laws. SCE&G 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 SCE&G 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 until at least through 2017 and will cost an additional $18.5 million , which is accrued in Other within Deferred Credits and Other Liabilities on the consolidated balance sheet. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates. At December 31, 2015, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $34.8 million and are included in regulatory assets. Claims and Litigation Consolidated SCE&G is subject to various claims and litigation incidental to its business operations which management anticipates will be resolved without a material impact on Consolidated SCE&G’s results of operations, cash flows or financial condition. Operating Lease Commitments Consolidated SCE&G is obligated under various operating leases for rail cars, vehicles, office space, furniture and equipment. Leases expire at various dates through 2051. Rent expense totaled approximately $ 12.3 million in 2015, $ 12.1 million in 2014 and $ 13.6 million in 2013. Future minimum rental payments under such leases will be $4 million in 2016, $2 million in 2017, $1 million in 2018, $1 million in 2019, $1 million in 2020 and $17 million thereafter. Asset Retirement Obligations Consolidated SCE&G recognizes a liability for the present value of an ARO when incurred if the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional ARO is factored into the measurement of the liability when sufficient information exists, but such uncertainty is not a basis upon which to avoid liability recognition. The legal obligations associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation relate primarily to Consolidated SCE&G’s regulated utility operations. As of December 31, 2015, Consolidated SCE&G has recorded AROs of approximately $176 million for nuclear plant decommissioning (see Note 1) and AROs of approximately $312 million for other conditional obligations primarily related to generation, transmission and distribution properties, including gas pipelines. All of the amounts recorded are based upon estimates which are subject to varying degrees of imprecision, particularly since such payments will be made many years in the future. A reconciliation of the beginning and ending aggregate carrying amount of AROs is as follows: Millions of dollars 2015 2014 Beginning balance $ 536 $ 547 Liabilities incurred — 3 Liabilities settled (16 ) (6 ) Accretion expense 23 25 Revisions in

AFFILIATED TRANSACTIONS

AFFILIATED TRANSACTIONS	12 Months Ended
	Dec. 31, 2015
Affiliated Transaction [Line Items]
AFFILIATED TRANSACTIONS	AFFILIATED TRANSACTIONS The Company received cash distributions from equity-method investees of $4.0 million in 2015, $7.8 million in 2014 and $10.4 million in 2013. The Company made investments in equity-method investees of $4.1 million in 2015, $5.7 million in 2014 and $5.2 million in 2013. 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. SCE&G’s total purchases from this affiliate were $233.2 million in 2015, $260.3 million in 2014 and $134.2 million in 2013. SCE&G’s total sales to this affiliate were $232.0 million in 2015, $259.0 million in 2014 and $133.6 million in 2013. SCE&G’s payable to this affiliate was $12.9 million at December 31, 2015 and $27.9 million at December 31, 2014 SCE&G’s receivable from this affiliate was $12.8 million at December 31, 2015 and $27.8 million at December 31, 2014.
SCE&G
Affiliated Transaction [Line Items]
AFFILIATED TRANSACTIONS	AFFILIATED TRANSACTIONS 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, $30.0 million in 2014 and $33.3 million in 2013. SCE&G's payables to CGT for transportation services were $3.3 million at December 31, 2014, and SCE&G's receivables from CGT related to such transportation services were $1.2 million at December 31, 2014. SCE&G purchases natural gas and related pipeline capacity from SEMI to serve its retail gas customers and certain electric generation requirements. Such purchases totaled approximately $128.5 million in 2015, $195.7 million in 2014 and $166.9 million in 2013. SCE&G’s payables to SEMI for such purchases were $7.5 million and $12.6 million as of December 31, 2015 and 2014, respectively. 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. SCE&G’s total purchases from this affiliate were $233.2 million in 2015, $260.3 million in 2014 and $134.2 million in 2013. SCE&G’s total sales to this affiliate were $232.0 million in 2015, $259.0 million in 2014 and $133.6 million in 2013. SCE&G’s payable to this affiliate was $12.9 million at December 31, 2015 and $27.9 million at December 31, 2014 SCE&G’s receivable from this affiliate was $12.8 million at December 31, 2015 and $27.8 million at December 31, 2014. SCANA Services, for itself and its parent company, provides the following services to Consolidated SCE&G, which are rendered at direct or allocated cost: information systems services, telecommunications services, customer services, marketing and sales, human resources, corporate compliance, purchasing, financial services, risk management, public affairs, legal services, investor relations, gas supply and capacity management, strategic planning, general administrative services and retirement benefits. In addition, SCANA Services processes and pays invoices for Consolidated SCE&G and is reimbursed. Costs for these services totaled $300.0 million in 2015, $292.2 million in 2014 and $285.6 million in 2013. Consolidated SCE&G's payables to SCANA Services for these services were $57.0 million and $47.3 million at December 31, 2015 and 2014, respectively. 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 are described in Note 8.

SEGMENT OF BUSINESS INFORMATION

SEGMENT OF BUSINESS INFORMATION	12 Months Ended
	Dec. 31, 2015
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. The Company records intersegment sales and transfers of electricity and gas 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. Retail Gas Marketing markets natural gas in Georgia and is regulated as a marketer by the GPSC. Energy Marketing markets natural gas to industrial and large commercial customers and municipalities in the Southeast. All Other is comprised of the holding company and its other direct and indirect wholly-owned subsidiaries, which conduct nonregulated, energy-related operations. All Other also includes two additional subsidiaries prior to their sale in the first quarter of 2015 (see Note 13) and, in 2015, also includes within net income the holding company's gains on the sales of those businesses. None of these subsidiaries met the quantitative thresholds for determining reportable segments during any period reported. 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. Marketing segments differ from each other in their respective markets and customer type. Management uses operating income to measure segment profitability for SCE&G and other regulated operations and evaluates utility plant, net, for segments attributable to SCE&G. As a result, the Company does not allocate interest charges, income tax expense or assets other than utility plant to its segments. For nonregulated operations, management uses net income as the measure of segment profitability and evaluates total assets for financial position. Interest income is not reported by segment and is not material. The Company’s 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 the Company's 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 totals from SCANA or SCE&G 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. Deferred Tax Assets are adjusted to net them against deferred tax liabilities on a consolidated basis. Disclosure of Reportable Segments (Millions of dollars) Electric Operations Gas Distribution Retail Gas Marketing Energy Marketing All Other Adjustments/ Eliminations Consolidated Total 2015 External Revenue $ 2,551 $ 810 $ 449 $ 569 $ 5 $ (4 ) $ 4,380 Intersegment Revenue 6 2 — 128 413 (549 ) — Operating Income 876 152 n/a 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 12 6 1 333 393 Net Income n/a n/a 19 9 185 533 746 Segment Assets 10,883 2,606 106 95 998 2,458 17,146 Expenditures for Assets 1,087 203 — 2 15 (154 ) 1,153 Deferred Tax Assets 5 29 9 6 — (49 ) — 2014 External Revenue $ 2,622 $ 1,012 $ 515 $ 786 $ 37 $ (21 ) $ 4,951 Intersegment Revenue 7 2 — 196 437 (642 ) — Operating Income 768 159 n/a 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 16 3 12 177 248 Net Income (Loss) n/a n/a 26 5 (6 ) 513 538 Segment Assets 10,182 2,487 140 150 1,474 2,385 16,818 Expenditures for Assets 936 200 — 2 52 (98 ) 1,092 Deferred Tax Assets 11 29 11 9 15 (75 ) — 2013 External Revenue $ 2,423 $ 942 $ 465 $ 652 $ 40 $ (27 ) $ 4,495 Intersegment Revenue 6 1 — 167 416 (590 ) — Operating Income 679 153 n/a n/a 27 51 910 Interest Expense 19 22 1 — 4 251 297 Depreciation and Amortization 297 70 3 — 26 (18 ) 378 Income Tax Expense 6 33 15 4 14 151 223 Net Income (Loss) n/a n/a 24 6 (2 ) 443 471 Segment Assets 9,488 2,340 172 133 1,378 1,616 15,127 Expenditures for Assets 907 140 — 1 31 27 1,106 Deferred Tax Assets 10 27 8 2 14 (61 ) —
SCE&G
Segment Reporting Information [Line Items]
Segment Reporting Disclosure [Text Block]	SEGMENT OF BUSINESS INFORMATION Consolidated SCE&G’s reportable segments follow the same accounting policies as those described in Note 1 and reflect the effect of certain reclassifications described therein. Electric Operations primarily generates, transmits, and distributes electricity, and is regulated by the SCPSC and FERC. Gas Distribution purchases and sells natural gas, primarily at retail, and is regulated by the SCPSC. Management uses operating income to measure segment profitability for regulated operations and evaluates utility plant, net, for its segments. As a result, Consolidated SCE&G does not allocate interest charges, income tax expense, earnings available to common shareholder or assets other than utility plant to its segments. Intersegment revenue and interest income were not significant. Consolidated SCE&G’s deferred tax assets are netted with deferred tax liabilities for reporting purposes. The consolidated financial statements report operating revenues which are comprised of the reportable segments. Revenues from non-reportable segments are included in Other Income. Segment Assets include utility plant, net for all reportable segments. As a result, adjustments to assets include non-utility plant and non-fixed assets for the segments. Adjustments to Interest Expense and Deferred Tax Assets include amounts that are not allocated to the segments. Expenditures for Assets are adjusted for revisions to estimated cash flows related to AROs, and totals not allocated to other segments. Disclosure of Reportable Segments (Millions of dollars) Electric Operations Gas Distribution Adjustments/ Eliminations Consolidated Total 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 ) — 2013 External Revenue $ 2,431 $ 414 — $ 2,845 Operating Income 679 58 — 737 Interest Expense 19 — $ 198 217 Depreciation and Amortization 294 26 (7 ) 313 Segment Assets 9,488 686 2,499 12,673 Expenditures for Assets 907 45 51 1,003 Deferred Tax Assets 10 n/a (10 ) —

DISPOSITIONS (Notes)

DISPOSITIONS (Notes)	12 Months Ended
	Dec. 31, 2015
Dispositions [Abstract]
Disposal Group [Text Block]	DISPOSITIONS In December 2014, SCANA entered into definitive agreements to sell 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 closed in the first quarter of 2015. Proceeds from these sales, net of transaction costs, were approximately $647 million , and the pre-tax gain on the sales recognized during 2015 was approximately $341 million . 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. Accordingly, segment disclosures related to them are included within All Other in Note 12. As a result, the Company determined that the sales of CGT and SCI did not represent a strategic shift that had a major effect on its operations, and therefore, these sales did not meet the criteria for classification as discontinued operations. The carrying values of the major classes of assets and liabilities classified as held for sale in the consolidated balance sheet as of December 31, 2014, were as follows: Millions of dollars CGT SCI Total Assets Held for Sale Utility Plant, Net $ 288.4 — $ 288.4 Nonutility Property and Investments, Net 0.6 $ 40.1 40.7 Current Assets 6.5 3.9 10.4 Deferred Debits and Other Assets 0.9 0.2 1.1 Total Assets Held for Sale $ 296.4 $ 44.2 $ 340.6 Liabilities Held for Sale Current Liabilities $ 3.5 $ 2.2 $ 5.7 Deferred Credits and Other Liabilities 42.9 3.1 46.0 Total Liabilities Held for Sale $ 46.4 $ 5.3 $ 51.7

QUARTERLY FINANCIAL INFORMATION

QUARTERLY FINANCIAL INFORMATION (Notes)	12 Months Ended
	Dec. 31, 2015
Entity Information [Line Items]
Quarterly Financial Information [Text Block]	QUARTERLY FINANCIAL DATA (UNAUDITED) Millions of dollars, except per share amounts First Quarter Second Quarter Third Quarter Fourth Quarter Annual 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 2014 Total operating revenues $ 1,590 $ 1,026 $ 1,121 $ 1,214 $ 4,951 Operating income 350 154 269 234 1,007 Net income 193 96 144 105 538 Earnings per share 1.37 .68 1.01 .73 3.79
SCE&G
Entity Information [Line Items]
Quarterly Financial Information [Text Block]	QUARTERLY FINANCIAL DATA (UNAUDITED) Millions of dollars First Quarter Second Quarter Third Quarter Fourth Quarter Annual 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 2014 Total operating revenues $ 859 $ 698 $ 812 $ 722 $ 3,091 Operating income 239 145 272 174 830 Net Income 126 99 157 76 458 Earnings Available to Common Shareholder 123 96 154 73 446

SUMMARY OF SIGNIFICANT ACCOUN25

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2015
Significant Accounting Policies
Consolidation, Policy [Policy Text Block]	Organization and Principles of Consolidation 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. CGT and SCI were sold in the first quarter of 2015. Accordingly, the assets and liabilities of these entities are aggregated and shown as Assets held for sale and Liabilities held for sale in the December 31, 2014 consolidated balance sheet. See Note 13. The Company 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.
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 6.1% for 2015, 7.2% for 2014 and 6.9% for 2013. 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. The Company records provisions for depreciation and amortization 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 Note 13) 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: 2015 2014 2013 SCE&G 2.55 % 2.85 % 2.96 % GENCO 2.66 % 2.66 % 2.66 % CGT — 2.11 % 2.19 % PSNC Energy 2.94 % 2.98 % 3.01 % Weighted average of above 2.61 % 2.84 % 2.93 % 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 Summer Station 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, 2015 2014 Unit 1 New Units Unit 1 New Units Percent owned 66.7% 55.0% 66.7% 55.0% Plant in service $ 1.2 billion — $ 1.2 billion — Accumulated depreciation $ 620.4 million — $ 578.3 million — Construction work in progress $ 214.6 million $ 3.4 billion $ 199.3 million $ 2.7 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 Summer Station Unit 1 and the New Units. These amounts totaled $178.8 million at December 31, 2015 and $88.9 million at December 31, 2014.
Plant to be retired [Policy Text Block]	Plant to be Retired At December 31, 2014, SCE&G expected to retire three units that are or were coal-fired by 2020, which was prior to the end of the previously estimated useful lives over which the units were being depreciated. As such, these units were identified as Plant to be Retired. Subsequently, these units were converted to be gas-fired. In the third quarter of 2015, in connection with the adoption of a customary depreciation study and related analysis (see Note 2), SCE&G determined that these units would not likely be retired by 2020, and their depreciation rates were set to recover the units' net carrying value over their respective revised useful lives. Accordingly, the net carrying value of these units is no longer classified as Plant to be Retired 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. Through 2017, 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, 2015 and 2014, SCE&G incurred $16.5 million and $19.4 million , respectively, for turbine maintenance. Nuclear refueling outages are scheduled 18 months apart. As approved by the SCPSC, effective January 1, 2013, SCE&G accrues $1.4 million per month for its portion of the nuclear refueling outages that are scheduled for the spring of 2014 through the spring of 2020. Total costs for 2014 were $43.7 million , of which SCE&G was responsible for $29.1 million . Total costs for 2015 were $40.2 million , of which SCE&G was respons
Goodwill and Intangible Assets, Goodwill, Policy [Policy Text Block]	Goodwill The Company considers certain amounts categorized by FERC as “acquisition adjustments” to be goodwill. For each period presented, assets with a carrying value of $210 million (net of a writedown taken in 2002 of $230 million ) for PSNC Energy (Gas Distribution segment) were classified as goodwill. The Company tests goodwill for impairment annually as of January 1, unless indicators, events or circumstances require interim testing to be performed. The goodwill impairment testing is generally a two-step quantitative process which in 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. Accounting guidance adopted by the Company gives it the option to first perform a qualitative assessment of impairment. Based on this qualitative ("step zero") 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 the two-step quantitative assessment. In evaluations of PSNC Energy, fair value was estimated using the assistance of an independent appraisal. In evaluations for the periods presented, step one has indicated no impairment, and no impairment charges have been recorded. Should a write-down be required in the future, such a charge would be treated as an operating expense.
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 Summer Station Unit 1, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $696.8 million , stated in 2012 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Summer Station 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, amounts collected through rates ( $3.2 million pre-tax in each period presented) are invested in insurance policies on the lives of certain Company personnel. SCE&G transfers to an external trust fund the amounts collected through electric rates, insurance proceeds and interest thereon, less expenses. 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 Summer Station Unit 1 on an after-tax basis.
Cash and Cash Equivalents, Policy [Policy Text Block]	Cash and Cash Equivalents The Company considers temporary cash investments having original maturities of three months or less at time of purchase 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]	Asset Management and Supply Service Agreements PSNC Energy utilizes asset management and supply service agreements with counterparties for certain natural gas storage facilities. Such counterparties held 46% and 48% of PSNC Energy’s natural gas inventory at December 31, 2015 and December 31, 2014, respectively, with a carrying value of $17.7 million and $26.1 million , respectively, through either capacity release or agency relationships. Under the terms of the asset management agreements, PSNC Energy receives storage asset management fees. No fees are received under supply service agreements. The agreements expire March 31, 201
Income Tax, Policy [Policy Text Block]	Income Taxes The Company 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.
regulatory assets and regulatory liabilities [Policy Text Block]	Regulatory Assets and Regulatory Liabilities The Company’s rate-regulated utilities record costs that have been or are expected to be allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense or record revenue in a period different from the period in which the revenue would be recorded by a nonregulated enterprise. These expenses deferred for future recovery from customers or obligations to be refunded 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.
Debt Premium, Discount, and Expense [Policy Text Block]	Debt Issuance Premiums, Discounts and Other Costs The Company presents long-term debt premiums, discounts and debt issuance costs within long-term debt and amortizes them 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 The Company maintains an environmental assessment program 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 The Company presents the revenues and expenses of its regulated businesses and its retail natural gas marketing businesses (including those activities of segments described in Note 12) within operating income, and it presents all other activities within other income (expense). Consistent with this presentation, the gain on the sale of CGT is reflected within operating income and the gain on the sale of SCI is reflected within other income (expense).
Revenue Recognition, Policy [Policy Text Block]	Revenue Recognition The Company records revenues during the accounting period in which it provides services to customers and includes estimated amounts for electricity and natural gas delivered but not billed. Unbilled revenues totaled $129.1 million at December 31, 2015 and $186.4 million at December 31, 2014. 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. An eWNA for SCE&G's electric customers was discontinued effective with the first billing cycle of 2014 as approved by the SCPSC. 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 that are 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 The Company computes basic earnings per share by dividing net income by the weighted average number of common shares outstanding for the period. The Company computes diluted earnings per share using this same formula, after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method. The weighted average number of common shares for each period presented for basic and diluted earnings per share purposes were identical, except that for 2013, the net effect of equity forward contracts resulted in such shares for diluted earnings per share purposes being 0.4 million higher than for basic earnings per share purposes.
New Accounting Matters [Policy Text Block]	New Accounting Matters In April 2014, the FASB issued accounting guidance for reporting discontinued operations and disclosures of disposals of components of an entity. Under this guidance, only those discontinued operations which represent a strategic shift that will have a major effect on an entity’s operations and financial results should be reported as discontinued operations in the financial statements. As permitted, the Company adopted this guidance for the period ended December 31, 2014. In May 2014, the FASB issued accounting guidance for revenue arising from contracts with customers that supersedes most current revenue recognition guidance, including industry-specific guidance. This 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 is required to adopt this guidance in the first quarter of 2018 and early adoption is permitted in the first quarter of 2017. Adoption using a retrospective method is required, with options to elect certain practical expedients or to recognize a cumulative effect in the year of initial adoption. The Company has not determined when it will adopt this guidance or what elections it will make. The Company has not determined the impact this guidance will have on its results of operations, cash flows or financial position. In April 2015, the FASB issued accounting guidance related to fees paid by a customer in a cloud computing arrangement. Among other things, the guidance clarifies how to account for a software license element included in a cloud computing arrangement, and makes explicit that a cloud computing arrangement not containing a software license element should be accounted for as a service contract. The Company has determined that this guidance, when adopted in the first quarter of 2016, will not significantly impact the Company’s results of operations, cash flows or financial position. In July 2015, the FASB issued accounting guidance intended to simplify the subsequent measurement of inventory cost by requiring most inventory to be measured at the lower of cost and net realizable value. The Company expects to adopt this guidance when required in the first quarter of 2017. The Company is evaluating this guidance and has not determined what impact it will have on its results of operations, cash flows or financial position. In January 2016, the FASB issued accounting guidance intended to clarify the classification and measurement of financial instruments and financial liabilities, among other things. The Company expects to adopt this guidance when required in the first quarter of 2018. The Company is evaluating this guidance and has not determined what impact it will have on its results of operations, cash flows or financial position. 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 twelve 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 of 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 has not determined what impact this guidance will have on its results of operations, cash flows or financial position.
SCE&G
Significant Accounting Policies
Consolidation, Policy [Policy Text Block]	Organization and Principles of Consolidation 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, the accompanying 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. Accordingly, 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 megawatt 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 $491 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. Consolidated SCE&G calculated AFC using average composite rates of 5.6% for 2015, 6.5% for 2014 and 6.9% for 2013. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561. SCE&G capitalizes interest on nuclear fuel in process at the actual interest cost incurred. Consolidated SCE&G records provisions for depreciation and amortization 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. The composite weighted average depreciation rates for utility plant assets were 2.56% in 2015, 2.84% in 2014 and 2.94% in 2013. 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 Summer Station 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, 2015 2014 Unit 1 New Units Unit 1 New Units Percent owned 66.7% 55.0% 66.7% 55.0% Plant in service $ 1.2 billion — $ 1.2 billion — Accumulated depreciation $ 620.4 million — $ 578.3 million — Construction work in progress $ 214.6 million $ 3.4 billion $ 199.3 million $ 2.7 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 Summer Station Unit 1 and the New Units. These amounts totaled $178.8 million at December 31, 2015 and $88.9 million at December 31, 2014.
Plant to be retired [Policy Text Block]	Plant to be Retired At December 31, 2014, SCE&G expected to retire three units that are or were coal-fired by 2020, which was prior to the end of the previously estimated useful lives over which the units were being depreciated. As such, these units were identified as Plant to be Retired. Subsequently, these units were converted to be gas-fired. In the third quarter of 2015, in connection with the adoption of a customary depreciation study and related analysis (see Note 2), SCE&G determined that these units would not likely be retired by 2020, and their depreciation rates were set to recover the units' net carrying value over their respective revised useful lives. Accordingly, the net carrying value of these units is no longer classified as Plant to be Retired 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 are classified as a regulatory asset or regulatory liability on the consolidated balance sheet. Other planned major maintenance is expensed when incurred. Through 2017, 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, 2015 and 2014, SCE&G incurred $16.5 million and $19.4 million , respectively, for turbine maintenance. Nuclear refueling outages are scheduled 18 months apart. As approved by the SCPSC, effective January 1, 2013, SCE&G accrues $1.4 million per month for its portion of the nuclear refueling outages that are scheduled for the spring of 2014 throught the spring of 2020. Total costs for 2014 were $43.7 million , of which SCE&G was responsible for $29.1 million . Total costs for 2015 were $40.2 million , of which SCE&G was responsible for $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 Summer Station Unit 1, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $696.8 million , stated in 2012 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Summer Station 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, amounts collected through rates ( $3.2 million pre-tax in each period presented) are invested in insurance policies on the lives of certain SCE&G and affiliate personnel. SCE&G transfers to an external trust fund the amounts collected through electric rates, insurance proceeds and interest thereon, less expenses. 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 Summer Station Unit 1 on an after-tax basis.
Cash and Cash Equivalents, Policy [Policy Text Block]	Cash and Cash Equivalents Consolidated SCE&G considers temporary cash investments having original maturities of three months or less at time of purchase 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.
Income tax presentation policy [Policy Text Block]	Income Taxes Consolidated SCE&G is included in the consolidated federal income tax returns of SCANA. Under a joint consolidated income tax allocation agreement, each SCANA 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; otherwise, they are charged or credited to income tax expense. 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 Consolidated SCE&G records costs that have been or are expected to be allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense or record revenue in a period different from the period in which the revenue would be recorded by a nonregulated enterprise. These expenses deferred for future recovery from customers or obligations to be refunded 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.
Debt Premium, Discount, and Expense [Policy Text Block]	Debt Issuance Premiums, Discounts and Other Costs Consolidated SCE&G presents long-term debt premiums, discounts and debt issuance costs within long-term debt and amortizes them as components of interest charges over the terms of the respective debt issues. 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 SCE&G maintains an environmental assessment program 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 Consolidated SCE&G presents the revenues and expenses of its regulated activities (including those activities of segments described in Note 12) within operating income, and it presents all other activities within other income (expense).
Revenue Recognition, Policy [Policy Text Block]	Revenue Recognition Consolidated SCE&G records revenues during the accounting period in which it provides services to customers and includes estimated amounts for electricity and natural gas delivered but not billed. Unbilled revenues totaled $101.5 million at December 31, 2015 and $115.8 million at December 31, 2014. 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. Customers subject to the 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. 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. An eWNA for SCE&G's electric customers was discontinued effective with the first billing cycle of 2014 as approved by the SCPSC. Taxes that are 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 current revenue recognition guidance, including industry-specific guidance. This 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. Consolidated SCE&G is required to adopt this guidance in the first quarter of 2018 and early adoption is permitted in the first quarter of 2017. Adoption using a retrospective method is required, with options to elect certain practical expedients or to recognize a cumulative effect in the year of initial adoption. Consolidated SCE&G has not determined when it will adopt this guidance or what elections it will make. Consolidated SCE&G has not determined the impact this guidance will have on its results of operations, cash flows or financial position. In April 2015, the FASB issued accounting guidance related to fees paid by a customer in a cloud computing arrangement. Among other things, the guidance clarifies how to account for a software license element included in a cloud computing arrangement, and makes explicit that a cloud computing arrangement not containing a software license element should be accounted for as a service contract. Consolidated SCE&G has determined that this guidance, when adopted in the first quarter of 2016, will not significantly impact Consolidated SCE&G’s results of operations, cash flows or financial position. In July 2015, the FASB issued accounting guidance intended to simplify the subsequent measurement of inventory cost by requiring most inventory to be measured at the lower of cost and net realizable value. Consolidated SCE&G expects to adopt this guidance when required in the first quarter of 2017. Consolidated SCE&G is evaluating this guidance and has not determined what impact it will have on its results of operations, cash flows or financial position. In January 2016, the FASB issued accounting guidance intended to clarify the classification and measurement of financial instruments and financial liabilities, among other things. Consolidated SCE&G expects to adopt this guidance when required in the first quarter of 2018. Consolidated SCE&G is evaluating this guidance and has not determined what impact it will have on its results of operations, cash flows or financial position. 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 twelve 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 of 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 year beginning in 2019. Consolidated SCE&G has not determined what impact this guidance will have on its results of operations, cash flows or financial position.

SUMMARY OF SIGNIFICANT ACCOUN26

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2015
Significant Accounting Policies
Schedule of weighted avg depreciation rates [Table Text Block]	2015 2014 2013 SCE&G 2.55 % 2.85 % 2.96 % GENCO 2.66 % 2.66 % 2.66 % CGT — 2.11 % 2.19 % PSNC Energy 2.94 % 2.98 % 3.01 % Weighted average of above 2.61 % 2.84 % 2.93 %
Schedule of Jointly Owned Utility Plants [Table Text Block]	As of December 31, 2015 2014 Unit 1 New Units Unit 1 New Units Percent owned 66.7% 55.0% 66.7% 55.0% Plant in service $ 1.2 billion — $ 1.2 billion — Accumulated depreciation $ 620.4 million — $ 578.3 million — Construction work in progress $ 214.6 million $ 3.4 billion $ 199.3 million $ 2.7 billion
SCE&G
Significant Accounting Policies
Schedule of Jointly Owned Utility Plants [Table Text Block]	As of December 31, 2015 2014 Unit 1 New Units Unit 1 New Units Percent owned 66.7% 55.0% 66.7% 55.0% Plant in service $ 1.2 billion — $ 1.2 billion — Accumulated depreciation $ 620.4 million — $ 578.3 million — Construction work in progress $ 214.6 million $ 3.4 billion $ 199.3 million $ 2.7 billion

RATE AND OTHER REGULATORY MAT27

RATE AND OTHER REGULATORY MATTERS (Tables)	12 Months Ended
	Dec. 31, 2015
Public Utilities, General Disclosures
Demand reduction programs [Table Text Block]	Year Effective Amount 2015 First billing cycle of May $32.0 million 2014 First billing cycle of May $15.4 million 2013 First billing cycle of May $16.9 million
Schedule of Changes in Electric Rate BLRA [Table Text Block]	Year Increase Amount 2015 2.6% $64.5 million 2014 2.8% $66.2 million 2013 2.9% $67.2 million
Schedule of Changes in Gas Rate RSA [Table Text Block]	Year Action Amount 2015 No change — 2014 0.6 % Decrease $2.6 million 2013 No change —
Schedule of Regulatory Assets [Table Text Block]	. December 31, Millions of dollars 2015 2014 Regulatory Assets: Accumulated deferred income taxes $ 298 $ 284 AROs and related funding 405 366 Deferred employee benefit plan costs 325 350 Deferred losses on interest rate derivatives 535 453 Unrecovered plant 127 137 Environmental remediation costs 42 40 DSM Programs 61 56 Other 144 137 Total Regulatory Assets $ 1,937 $ 1,823
Schedule of Regulatory Liabilities [Table Text Block]	Regulatory Liabilities: Asset removal costs $ 732 $ 703 Deferred gains on interest rate derivatives 96 82 Other 27 29 Total Regulatory Liabilities $ 855 $ 814
SCE&G
Public Utilities, General Disclosures
Demand reduction programs [Table Text Block]	Year Effective Amount 2015 First billing cycle of May $32.0 million 2014 First billing cycle of May $15.4 million 2013 First billing cycle of May $16.9 million
Schedule of Changes in Electric Rate BLRA [Table Text Block]	Year Increase Amount 2015 2.6% $64.5 million 2014 2.8% $66.2 million 2013 2.9% $67.2 million
Schedule of Changes in Gas Rate RSA [Table Text Block]	Year Action Amount 2015 No change — 2014 0.6 % Decrease $ 2.6 million 2013 No change —
Schedule of Regulatory Assets [Table Text Block]	. December 31, Millions of dollars 2015 2014 Regulatory Assets: Accumulated deferred income taxes $ 291 $ 278 AROs and related funding 384 347 Deferred employee benefit plan costs 295 310 Deferred losses on interest rate derivatives 535 453 Unrecovered plant 127 137 Environmental remediation costs 35 36 DSM Programs 61 56 Other 129 128 Total Regulatory Assets $ 1,857 $ 1,745
Schedule of Regulatory Liabilities [Table Text Block]	Regulatory Liabilities: Asset removal costs 519 505 Deferred gains on interest rate derivatives 96 82 Other 20 23 Total Regulatory Liabilities $ 635 $ 610

LONG-TERM AND SHORT-TERM DEBT (

LONG-TERM AND SHORT-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Instrument [Line Items]
Schedule of Debt [Table Text Block]	: 2015 2014 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) 2016 - 2034 84 1.11 % 88 0.93 % SCE&G First Mortgage Bonds (secured) 2018 - 2065 4,340 5.78 % 3,840 5.56 % GENCO Notes (secured) 2016 - 2024 220 5.92 % 227 5.90 % Industrial and Pollution Control Bonds (b) 2028 - 2038 122 3.51 % 122 3.51 % PSNC Senior Debentures 2020 - 2026 350 5.93 % 350 5.93 % Nuclear Fuel Financing 2016 100 0.78 % 100 0.78 % Other (c) 2016 - 2027 18 2.72 % 167 7.39 % Total debt 6,034 5,694 Current maturities of long-term debt (116 ) (166 ) Unamortized premium, net — 3 Unamortized debt issuance costs (36 ) (34 ) Total long-term debt, net $ 5,882 $ 5,497
Schedule of Line of Credit Facilities [Text Block]	SCANA SCE&G PSNC Energy Millions of dollars 2015 2014 2015 2014 2015 2014 Lines of Credit: Total committed long-term $ 400 $ 300 $ 1,400 $ 1,400 $ 200 $ 100 Outstanding commercial paper (270 or fewer days) $ 37 $ 179 $ 420 $ 709 $ 74 $ 30 Weighted average interest rate 1.19 % 0.54 % 0.74 % 0.52 % 0.77 % 0.65 % Letters of credit supported by LOC $ 3 $ 3 $ 0.3 $ 0.3 — — Available $ 360 $ 118 $ 980 $ 691 $ 126 $ 70
SCE&G
Debt Instrument [Line Items]
Schedule of Debt [Table Text Block]	2015 2014 Dollars in millions Maturity Balance Rate Balance Rate First Mortgage Bonds (secured) 2018 - 2065 $ 4,340 5.78 % $ 3,840 5.56 % GENCO Notes (secured) 2016 - 2024 220 5.92 % 227 5.90 % Industrial and Pollution Control Bonds (a) 2028 - 2038 122 3.51 % 122 3.51 % Nuclear Fuel Financing 2016 100 0.78 % 100 0.78 % Other 2016 - 2027 17 2.63 % 14 2.63 % Total debt 4,799 4,303 Current maturities of long-term debt (110 ) (10 ) Unamortized premium, net 2 6 Unamortized debt issuance costs (32 ) (29 ) Total long-term debt, net $ 4,659 $ 4,270
Schedule of Line of Credit Facilities [Text Block]	: Millions of dollars 2015 2014 Lines of credit: Total committed long-term $ 1,400 $ 1,400 Outstanding commercial paper (270 or fewer days) $ 420 $ 709 Weighted average interest rate 0.74 % 0.52 % Letters of credit supported by an LOC $ 0.3 $ 0.3 Available $ 980 $ 691

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2015
Investments, Owned, Federal Income Tax Note [Line Items]
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	: Millions of dollars 2015 2014 2013 Current taxes: Federal $ 382 $ 38 $ 161 State 57 (4 ) 17 Total current taxes 439 34 178 Deferred tax (benefit) expense, net: Federal (36 ) 184 39 State (7 ) 34 10 Total deferred taxes (43 ) 218 49 Investment tax credits: Amortization of amounts deferred-state (1 ) (1 ) (1 ) Amortization of amounts deferred-federal (2 ) (3 ) (3 ) Total investment tax credits (3 ) (4 ) (4 ) Total income tax expense $ 393 $ 248 $ 223
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	: Millions of dollars 2015 2014 2013 Net income $ 746 $ 538 $ 471 Income tax expense 393 248 223 Total pre-tax income $ 1,139 $ 786 $ 694 Income taxes on above at statutory federal income tax rate $ 399 $ 275 $ 243 Increases (decreases) attributed to: State income taxes (less federal income tax effect) 38 24 22 State investment tax credits (less federal income tax effect) (6 ) (5 ) (5 ) Allowance for equity funds used during construction (9 ) (11 ) (9 ) Deductible dividends—401(k) Retirement Savings Plan (10 ) (10 ) (10 ) Amortization of federal investment tax credits (2 ) (3 ) (3 ) Section 41 tax credits 1 (3 ) — Section 45 tax credits (9 ) (9 ) (5 ) Domestic production activities deduction (18 ) (7 ) (11 ) Realization of basis differences upon sale of subsidiaries 7 — — Other differences, net 2 (3 ) 1 Total income tax expense $ 393 $ 248 $ 223
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	: Millions of dollars 2015 2014 Deferred tax assets: Nondeductible accruals $ 135 $ 127 Asset retirement obligation, including nuclear decommissioning 199 216 Financial instruments 35 40 Unamortized investment tax credits 16 17 Deferred fuel costs 8 — Monetization of bankruptcy claim — 10 Other 5 10 Total deferred tax assets 398 420 Deferred tax liabilities: Property, plant and equipment $ 1,906 $ 1,928 Deferred employee benefit plan costs 96 107 Regulatory asset, asset retirement obligation 135 122 Deferred fuel costs — 27 Regulatory asset, unrecovered plant 49 53 Regulatory asset, net loss on interest rate derivative contracts settlement — 21 Demand side management costs 23 21 Prepayments 31 27 Other 65 45 Total deferred tax liabilities 2,305 2,351 Net deferred tax liability $ 1,907 $ 1,931
Schedule of Unrecognized Tax Benefits Roll Forward [Table Text Block]	Millions of dollars 2015 2014 2013 Unrecognized tax benefits, January 1 $ 16 $ 3 — Gross increases—uncertain tax positions in prior period 33 — — Gross decreases—uncertain tax positions in prior period (2 ) — — Gross increases—current period uncertain tax positions 2 13 $ 3 Unrecognized tax benefits, December 31 $ 49 $ 16 $ 3
SCE&G
Investments, Owned, Federal Income Tax Note [Line Items]
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	Millions of dollars 2015 2014 2013 Current taxes: Federal $ 208 $ 39 $ 146 State 32 (6 ) 13 Total current taxes 240 33 159 Deferred tax (benefit) expense, net: Federal (3 ) 157 25 State (3 ) 32 9 Total deferred taxes (6 ) 189 34 Investment tax credits: Amortization of amounts deferred—state (1 ) (1 ) (1 ) Amortization of amounts deferred—federal (2 ) (3 ) (3 ) Total investment tax credits (3 ) (4 ) (4 ) Total income tax expense $ 231 $ 218 $ 189
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	Millions of dollars 2015 2014 2013 Net income $ 466 $ 446 $ 380 Income tax expense 231 218 189 Noncontrolling interest 14 12 11 Total pre-tax income $ 711 $ 676 $ 580 Income taxes on above at statutory federal income tax rate $ 249 $ 237 $ 203 Increases (decreases) attributed to: State income taxes (less federal income tax effect) 24 21 18 State investment tax credits (less federal income tax effect) (6 ) (5 ) (5 ) Allowance for equity funds used during construction (9 ) (10 ) (9 ) Amortization of federal investment tax credits (2 ) (3 ) (3 ) Section 41 tax credits 1 (3 ) — Section 45 tax credits (9 ) (9 ) (5 ) Domestic production activities deduction (18 ) (7 ) (11 ) Other differences, net 1 (3 ) 1 Total income tax expense $ 231 $ 218 $ 189
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	Millions of dollars 2015 2014 Deferred tax assets: Nondeductible accruals $ 52 $ 47 Asset retirement obligation, including nuclear decommissioning 187 205 Unamortized investment tax credits 16 17 Deferred fuel costs 7 — Financial instruments 2 — Other 2 6 Total deferred tax assets 266 275 Deferred tax liabilities: Property, plant and equipment $ 1,644 $ 1,623 Regulatory asset, asset retirement obligation 127 115 Deferred employee benefit plan costs 85 91 Deferred fuel costs — 27 Regulatory asset, unrecovered plant 49 53 Regulatory asset, net loss on interest rate derivative contracts settlement — 21 Demand side management costs 23 21 Prepayments 29 25 Other 41 23 Total deferred tax liabilities 1,998 1,999 Net deferred tax liability $ 1,732 $ 1,724
Schedule of Unrecognized Tax Benefits Roll Forward [Table Text Block]	Millions of dollars 2015 2014 2013 Unrecognized tax benefits, January 1 $ 16 $ 3 — Gross increases-uncertain tax positions in prior period 33 — — Gross decreases-uncertain tax positions in prior period (2 ) — — Gross increases-current period uncertain tax positions 2 13 $ 3 Unrecognized tax benefits, December 31 $ 49 $ 16 $ 3

DERIVATIVE FINANCIAL INSTRUME30

DERIVATIVE FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative [Line Items]
Schedule of Derivative Instruments [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 Retail Gas Marketing Energy Marketing Total As of December 31, 2015 Commodity 7,530,000 7,869,000 3,973,500 19,372,500 Energy Management (a) — — 38,857,480 38,857,480 Total (a) 7,530,000 7,869,000 42,830,980 58,229,980 As of December 31, 2014 Commodity 6,840,000 7,951,000 3,446,720 18,237,720 Energy Management (b) — — 37,495,339 37,495,339 Total (b) 6,840,000 7,951,000 40,942,059 55,733,059 (a) Includes an aggregate 1,842,048 MMBTU related to basis swap contracts in Energy Marketing. (b) Includes an aggregate 933,893 MMBTU related to basis swap contracts in Energy Marketing.
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]	The fair value of derivatives in the consolidated balance sheets is as follows: Fair Values of Derivative Instruments Millions of dollars Balance Sheet Location Asset Liability As of December 31, 2015 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 4 Other deferred credits and other liabilities 28 Commodity contracts Other current assets 1 Derivative financial instruments 4 Total $ 37 Not designated as hedging instruments Interest rate contracts Other current assets $ 10 Other deferred debits and other assets 5 Derivative financial instruments $ 33 Other deferred credits and other liabilities 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 As of December 31, 2014 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 5 Other deferred credits and other liabilities 28 Commodity contracts Other current assets 1 Derivative financial instruments 11 Total $ 45 Not designated as hedging instruments Interest rate contracts Derivative financial instruments $ 207 Other deferred credits and other liabilities 17 Commodity contracts Other current assets $ 1 Energy management contracts Other current assets 15 5 Other deferred debits and other assets 5 Derivative financial instruments 10 Other deferred credits and other liabilities 5 Total $ 21 $ 244
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: Gain or (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, 2015 Interest rate contracts $ (3 ) Interest expense $ (3 ) Year Ended December 31, 2014 Interest rate contracts $ (9 ) Interest expense $ (3 ) Year Ended December 31, 2013 Interest rate contracts $ 106 Interest expense $ (3 ) 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, 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 ) Year Ended December 31, 2013 Interest rate contracts $ 5 Interest expense $ (8 ) Commodity contracts 2 Gas purchased for resale (3 ) Total $ 7 $ (11 )
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 Gain (Loss) Deferred in Regulatory Accounts Gain Reclassified from Deferred Accounts into Income Millions of dollars Location Amount Year Ended December 31, 2015 Interest rate contracts $ (69 ) Other income $ 5 Year Ended December 31, 2014 Interest rate contracts $ (352 ) Other income $ 64 Year Ended December 31, 2013 Interest rate contracts $ 39 Other income $ 50
Offsetting Assets [Table Text Block]	Information related to the Company's offsetting derivative assets and liabilities follows: Offsetting Derivative Assets Gross Amounts Offset in the Statement of Financial Position Net Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position Net Amount Millions of dollars Gross Amounts of Recognized Assets Financial Instruments Cash Collateral Received As of December 31, 2015 Interest rate $ 15 — $ 15 $ (8 ) — $ 7 Commodity 1 — 1 — — 1 Energy Management 15 $ (1 ) 14 — — 14 Total $ 31 $ (1 ) $ 30 $ (8 ) — $ 22 Balance sheet location Other current assets $ 22 Other deferred debits and other assets 8 Total $ 30 As of December 31, 2014 Commodity $ 1 — $ 1 — — $ 1 Energy Management 20 — 20 — — 20 Total $ 21 — $ 21 — — $ 21 Balance sheet location Other current assets $ 16 Other deferred debits and other assets 5 Total $ 21
Offsetting Liabilities [Table Text Block]	Offsetting Derivative Liabilities Gross Amounts Offset in the Statement of Financial Position Net Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position Net Amount Millions of dollars Gross Amounts of Recognized Liabilities Financial Instruments Cash Collateral Posted As of December 31, 2015 Interest rate $ 87 — $ 87 $ (8 ) $ (36 ) $ 43 Commodity 5 — 5 — (5 ) — Energy Management 15 $ (1 ) 14 — (9 ) 5 Total $ 107 $ (1 ) $ 106 $ (8 ) $ (50 ) $ 48 Balance sheet location Other current assets $ 3 Derivative financial instruments 50 Other deferred credits and other liabilities 53 Total $ 106 As of December 31, 2014 Interest rate $ 257 — $ 257 — $ (131 ) $ 126 Commodity 12 — 12 — (10 ) 2 Energy Management 20 — 20 — (11 ) 9 Total $ 289 — $ 289 — $ (152 ) $ 137 Balance sheet location Other current assets $ 6 Derivative financial instruments 233 Other deferred credits and other liabilities 50 Total $ 289
SCE&G
Derivative [Line Items]
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]	The fair value of derivatives in the consolidated balance sheets is as follows: Fair Values of Derivative Instruments Millions of dollars Balance Sheet Location Asset Liability As of December 31, 2015 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 1 Other deferred credits and other liabilities 9 Total $ 10 Not designated as hedging instruments Interest rate contracts Other current assets $ 10 Other deferred debits and other assets 5 Derivative financial instruments $ 33 Other deferred credits and other liabilities 22 Total $ 15 $ 55 As of December 31, 2014 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 1 Other deferred credits and other liabilities 8 Total $ 9 Not designated as hedging instruments Interest rate contracts Derivative financial instruments $ 207 Other deferred credits and other liabilities 17 Total $ 224
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: Derivatives in Cash Flow Hedging Relationships Gain (Loss) Deferred in Regulatory Accounts (Effective Portion) Gain (Loss) Reclassified from Deferred Accounts into Income (Effective Portion) Millions of dollars Location Amount Year Ended December 31, 2015 Interest rate contracts $ (3 ) Interest expense $ (3 ) Year Ended December 31, 2014 Interest rate contracts $ (9 ) Interest expense $ (3 ) Year Ended December 31, 2013 Interest rate contracts $ 106 Interest expense $ (3 )
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]	Gain or (Loss) Deferred in Regulatory Accounts Gain Reclassified from Deferred Accounts into Income Millions of dollars Location Amount Year Ended December 31, 2015 Interest rate contracts $ (69 ) Other income $ 5 Year Ended December 31, 2014 Interest rate contracts $ (352 ) Other income $ 64 Year Ended December 31, 2013 Interest rate contracts $ 39 Other income $ 50
Offsetting Assets [Table Text Block]	Information related to Consolidated SCE&G's offsetting derivative assets and liabilities follows: Offsetting Derivative Assets Gross Amounts Offset in the Statement of Financial Position Net Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position Net Amount Millions of dollars Gross Amounts of Recognized Assets Financial Instruments Cash Collateral Received As of December 31, 2015 Interest rate $ 15 — $ 15 $ (8 ) — $ 7 Balance sheet location Other current assets $ 10 Other deferred debits and other assets 5 Total $ 15
Offsetting Liabilities [Table Text Block]	Offsetting Derivative Liabilities Gross Amounts Offset in the Statement of Financial Position Net Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position Net Amount Millions of dollars Gross Amounts of Recognized Liabilities Financial Instruments Cash Collateral Posted As of December 31, 2015 Interest rate $ 65 — $ 65 $ (8 ) $ (13 ) $ 44 Balance sheet location Derivative financial instruments $ 34 Other deferred credits and other liabilities 31 Total $ 65 As of December 31, 2014 Interest rate $ 233 — $ 233 — $ (107 ) $ 126 Balance sheet location Derivative financial instruments $ 208 Other deferred credits and other liabilities 25 Total $ 233

FAIR VALUE MEASUREMENTS, INCL31

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Measurement Inputs, Disclosure [Table Text Block]	As of December 31, 2015 As of December 31, 2014 Millions of dollars Level 1 Level 2 Level 1 Level 2 Assets: Available for sale securities $ 11 — $ 13 — Interest rate contracts — $ 15 — — Commodity contracts 1 — 1 — Energy management contracts — 14 — $ 20 Liabilities: Interest rate contracts — 87 — 257 Commodity contracts 1 4 1 11 Energy management contracts 4 12 5 18
Fair Value, by Balance Sheet Grouping [Table Text Block]	As of December 31, 2015 As of December 31, 2014 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Long-term debt $ 5,997.6 $ 6,445.7 $ 5,663.1 $ 6,558.0
SCE&G
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Measurement Inputs, Disclosure [Table Text Block]	As of December 31, 2015 As of December 31, 2014 Millions of dollars Level 2 Level 2 Assets-Interest rate contracts $ 15 — Liabilities-Interest rate contracts 65 $ 233
Fair Value, by Balance Sheet Grouping [Table Text Block]	As of December 31, 2015 As of December 31, 2014 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Long-term debt $ 4,769.0 $ 5,129.1 $ 4,279.5 $ 5,041.9

EMPLOYEE BENEFIT PLANS (Tables)

EMPLOYEE BENEFIT PLANS (Tables)	12 Months Ended
	Dec. 31, 2015
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. Pension Benefits Other Postretirement Benefits Millions of dollars 2015 2014 2015 2014 Benefit obligation, January 1 $ 919.5 $ 823.0 $ 268.2 $ 238.0 Service cost 24.1 20.0 5.3 4.6 Interest cost 38.2 40.4 11.4 12.0 Plan participants’ contributions — — 2.4 2.2 Actuarial (gain) loss (62.4 ) 100.1 (21.2 ) 23.5 Benefits paid (64.0 ) (64.0 ) (12.5 ) (12.1 ) Benefit obligation, December 31 $ 855.4 $ 919.5 $ 253.6 $ 268.2
Schedule of Assumptions Used to Determine Benefit Obligations [Table Text Block]	Significant assumptions used to determine the above benefit obligations are as follows: Pension Benefits Other Postretirement Benefits 2015 2014 2015 2014 Annual discount rate used to determine benefit obligation 4.68 % 4.20 % 4.78 % 4.30 % Assumed annual rate of future salary increases for projected benefit obligation 3.00 % 3.00 % 3.00 % 3.00 %
Schedule of Net Funded Status [Table Text Block]	Millions of Dollars Pension Benefits Other Postretirement Benefits December 31, 2015 2014 2015 2014 Fair value of plan assets $ 781.7 $ 861.8 — — Benefit obligation 855.4 919.5 $ 253.6 $ 268.2 Funded status $ (73.7 ) $ (57.7 ) $ (253.6 ) $ (268.2 )
Schedule of Amounts Recognized in Balance Sheet [Table Text Block]	Amounts recognized on the consolidated balance sheets were as follows: Millions of Dollars Pension Benefits Other Postretirement Benefits December 31, 2015 2014 2015 2014 Current liability — — $ (11.9 ) $ (11.2 ) Noncurrent liability $ (73.7 ) $ (57.7 ) (241.7 ) (257.0 )
Schedule of Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income (Loss) [Table Text Block]	Amounts recognized in accumulated other comprehensive loss were as follows: Millions of Dollars Pension Benefits Other Postretirement Benefits December 31, 2015 2014 2015 2014 Net actuarial loss $ 10.4 $ 8.1 $ 1.7 $ 3.0 Prior service cost 0.2 0.3 — 0.1 Total $ 10.6 $ 8.4 $ 1.7 $ 3.1
Schedule of defined benefit plan, amounts recognized in regulatory assets [Table Text Block]	Amounts recognized in regulatory assets were as follows: Millions of Dollars Pension Benefits Other Postretirement Benefits December 31, 2015 2014 2015 2014 Net actuarial loss $ 219.4 $ 222.1 $ 24.0 $ 43.8 Prior service cost 5.9 9.6 0.3 0.6 Total $ 225.3 $ 231.7 $ 24.3 $ 44.4
Schedule of Changes in Fair Value of Plan Assets [Table Text Block]	Pension Benefits Millions of dollars 2015 2014 Fair value of plan assets, January 1 $ 861.8 $ 870.0 Actual return (loss) on plan assets (16.1 ) 55.8 Benefits paid (64.0 ) (64.0 ) Fair value of plan assets, December 31 $ 781.7 $ 861.8
Schedule of Allocation of Plan Assets [Table Text Block]	The Company’s pension plan asset allocation at December 31, 2015 and 2014 and the target allocation for 2016 are as follows: Percentage of Plan Assets Target Allocation December 31, Asset Category 2016 2015 2014 Equity Securities 58 % 57 % 57 % Fixed Income 33 % 32 % 34 % Hedge Funds 9 % 11 % 9 %
Schedule of Fair Value of Plan, Assets by Measurement Levels [Table Text Block]	Fair Value Measurements at Reporting Date Using Millions of dollars Total Level 2 Level 3 Total Level 2 Level 3 December 31, 2015 December 31, 2014 Mutual funds $ 538 $ 538 — $ 622 $ 622 — Short-term investment vehicles 14 14 — 20 20 — US Treasury securities 22 22 — 6 6 — Corporate debt securities 78 78 — 86 86 — Municipals 14 14 — 15 15 — Limited partnerships 33 33 — 32 32 — Multi‑strategy hedge funds 83 — $ 83 81 — $ 81 $ 782 $ 699 $ 83 $ 862 $ 781 $ 81
Schedule of Effect of Significant Unobservable Inputs, Changes in Plan Assets [Table Text Block]	Fair Value Measurements Level 3 Millions of dollars 2015 2014 Beginning Balance $ 81 $ 76 Unrealized gains included in changes in net assets 2 5 Purchases, issuances, and settlements — — Ending Balance $ 83 $ 81
Schedule of Expected Benefit Payments [Table Text Block]	Millions of dollars Pension Benefits Other Postretirement Benefits 2016 $ 65.1 $ 11.9 2017 63.2 12.7 2018 64.7 13.5 2019 65.3 14.2 2020 65.8 14.9 2021-2025 338.3 80.5
Schedule of Net Benefit Costs [Table Text Block]	Pension Benefits Other Postretirement Benefits Millions of dollars 2015 2014 2013 2015 2014 2013 Service cost $ 24.1 $ 20.0 $ 21.8 $ 5.3 $ 4.6 $ 5.9 Interest cost 38.2 40.4 38.5 11.4 12.0 11.1 Expected return on assets (62.0 ) (66.7 ) (61.4 ) n/a n/a n/a Prior service cost amortization 4.1 4.1 6.0 0.4 0.3 0.7 Amortization of actuarial losses 13.6 4.8 16.9 2.1 — 3.3 Transition obligation amortization — — — — — 0.3 Curtailment — — 9.9 — — — Net periodic benefit cost $ 18.0 $ 2.6 $ 31.7 $ 19.2 $ 16.9 $ 21.3
Schedule of Defined Benefit Plan Amounts Recognized in Other Comprehensive Income (Loss) [Table Text Block]	Other changes in plan assets and benefit obligations recognized in OCI (net of tax) were as follows: Pension Benefits Other Postretirement Benefits Millions of dollars 2015 2014 2013 2015 2014 2013 Current year actuarial (gain) loss $ 2.7 $ 3.1 $ (5.0 ) $ (1.2 ) $ 1.3 $ (1.8 ) Amortization of actuarial losses (0.4 ) (0.2 ) (0.5 ) (0.1 ) — (0.2 ) Amortization of prior service cost (0.1 ) (0.2 ) (0.2 ) (0.1 ) — — Prior service cost (credit) — — (0.3 ) — — — Amortization of transition obligation — — — — — (0.1 ) Total recognized in OCI $ 2.2 $ 2.7 $ (6.0 ) $ (1.4 ) $ 1.3 $ (2.1 )
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: Pension Benefits Other Postretirement Benefits Millions of dollars 2015 2014 2013 2015 2014 2013 Current year actuarial (gain) loss $ 9.2 $ 101.3 $ (157.5 ) $ (18.0 ) $ 19.4 $ (29.9 ) Amortization of actuarial losses (11.9 ) (4.0 ) (14.7 ) (1.8 ) — (2.7 ) Amortization of prior service cost (3.7 ) (3.2 ) (5.2 ) (0.3 ) (0.3 ) (0.6 ) Prior service cost (credit) — — (8.9 ) — — — Amortization of transition obligation — — — — — (0.2 ) Total recognized in regulatory assets $ (6.4 ) $ 94.1 $ (186.3 ) $ (20.1 ) $ 19.1 $ (33.4 )
Schedule of Assumptions Used in Determining Net Periodic Benefit Cost [Table Text Block]	Pension Benefits Other Postretirement Benefits 2015 2014 2013 2015 2014 2013 Discount rate 4.20 % 5.03 % 4.10%/5.07% 4.30 % 5.19 % 4.19 % Expected return on plan assets 7.50 % 8.00 % 8.00 % n/a n/a n/a Rate of compensation increase 3.00 % 3.00 % 3.75%/3.00% 3.00 % 3.75 % 3.75 % Health care cost trend rate n/a n/a n/a 7.00 % 7.40 % 7.80 % 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 2020 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 2016 are as follows: Millions of Dollars Pension Benefits Other Postretirement Benefits Actuarial loss $ 0.6 — Prior service cost 0.2 — Total $ 0.8 —
Schedule of amounts in regulatory assets to be recognized over the next fiscal year [Table Text Block]	The estimated amounts to be amortized from regulatory assets into net periodic benefit cost in 2016 are as follows: Millions of Dollars Pension Benefits Other Postretirement Benefits Actuarial loss $ 12.7 $ 0.3 Prior service cost 3.4 0.3 Total $ 16.1 $ 0.6
SCE&G
Defined Benefit Plan Disclosure [Line Items]
Schedule of Changes in Projected Benefit Obligations [Table Text Block]	Pension Benefits Other Postretirement Benefits Millions of dollars 2015 2014 2015 2014 Benefit obligation, January 1 $ 773.7 $ 695.7 $ 204.1 $ 181.7 Service cost 19.3 16.0 4.4 3.6 Interest cost 32.2 34.1 9.4 9.4 Plan participants’ contributions — — 1.9 1.8 Actuarial (gain) loss (47.0 ) 82.7 (15.7 ) 18.6 Benefits paid (54.2 ) (54.8 ) (10.3 ) (9.6 ) Amounts funded to parent — — (2.1 ) (1.4 ) Benefit obligation, December 31 $ 724.0 $ 773.7 $ 191.7 $ 204.1
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 2015 2014 2015 2014 Annual discount rate used to determine benefit obligation 4.68 % 4.20 % 4.78 % 4.30 % Assumed annual rate of future salary increases for projected benefit obligation 3.00 % 3.00 % 3.00 % 3.00 %
Schedule of Net Funded Status [Table Text Block]	Funded Status Millions of Dollars Pension Benefits Other Postretirement Benefits December 31, 2015 2014 2015 2014 Fair value of plan assets $ 720.1 $ 783.6 — — Benefit obligation 724.0 773.7 $ 191.7 $ 204.1 Funded status $ (3.9 ) $ 9.9 $ (191.7 ) $ (204.1 )
Schedule of Amounts Recognized in Balance Sheet [Table Text Block]	Amounts recognized on the consolidated balance sheets were as follows: Millions of Dollars Pension Benefits Other Postretirement Benefits December 31, 2015 2014 2015 2014 Current liability — — $ (9.8 ) $ (8.5 ) Noncurrent asset — $ 9.9 — — Noncurrent liability $ (3.9 ) — (181.9 ) (195.6 )
Schedule of Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income (Loss) [Table Text Block]	Amounts recognized in accumulated other comprehensive loss were as follows: Millions of Dollars Pension Benefits Other Postretirement Benefits December 31, 2015 2014 2015 2014 Net actuarial loss $ 2.0 $ 1.9 $ 0.7 $ 1.0 Prior service cost — 0.1 — — Total $ 2.0 $ 2.0 $ 0.7 $ 1.0
Schedule of defined benefit plan, amounts recognized in regulatory assets [Table Text Block]	Amounts recognized in regulatory assets were as follows: Millions of Dollars Pension Benefits Other Postretirement Benefits December 31, 2015 2014 2015 2014 Net actuarial loss $ 193.7 $ 191.9 $ 20.4 $ 35.9 Prior service cost 5.2 8.3 0.2 0.5 Total $ 198.9 $ 200.2 $ 20.6 $ 36.4
Schedule of Changes in Fair Value of Plan Assets [Table Text Block]	Changes in Fair Value of Plan Assets Pension Benefits Millions of dollars 2015 2014 Fair value of plan assets, January 1 $ 783.6 $ 792.1 Actual return (loss) on plan assets (9.3 ) 46.3 Benefits paid (54.2 ) (54.8 ) Fair value of plan assets, December 31 $ 720.1 $ 783.6
Schedule of Allocation of Plan Assets [Table Text Block]	The pension plan asset allocation at December 31, 2015 and 2014 and the target allocation for 2016 are as follows: Percentage of Plan Assets Target Allocation December 31, Asset Category 2016 2015 2014 Equity Securities 58 % 57 % 57 % Fixed Income 33 % 32 % 34 % Hedge Funds 9 % 11 % 9 %
Schedule of Fair Value of Plan, Assets by Measurement Levels [Table Text Block]	Fair Value Measurements at Reporting Date Using Millions of dollars Total Level 2 Level 3 Total Level 2 Level 3 December 31, 2015 December 31, 2014 Mutual funds $ 496 $ 496 — $ 566 $ 566 — Short-term investment vehicles 12 12 — 18 18 — US Treasury securities 20 20 — 6 6 — Corporate debt securities 72 72 — 78 78 — Municipals 13 13 — 14 14 — Limited partnerships 30 30 — 29 29 — Multi-strategy hedge funds 77 — $ 77 73 — $ 73 $ 720 $ 643 $ 77 $ 784 $ 711 $ 73
Schedule of Effect of Significant Unobservable Inputs, Changes in Plan Assets [Table Text Block]	Fair Value Measurements Level 3 Millions of dollars 2015 2014 Beginning Balance $ 73 $ 69 Unrealized gains included in changes in net assets 4 4 Purchases, issuances, and settlements — — Ending Balance $ 77 $ 73
Schedule of Expected Benefit Payments [Table Text Block]	The total benefits expected to be paid from the pension plan or from Consolidated SCE&G’s assets for the other postretirement benefits plan (net of participant contributions), respectively, are as follows: Expected Benefit Payments Millions of dollars Pension Benefits Other Postretirement Benefits 2016 $ 65.1 $ 9.8 2017 63.2 10.5 2018 64.7 11.1 2019 65.3 11.7 2020 65.8 12.3 2021 - 2025 338.3 66.1
Schedule of Net Benefit Costs [Table Text Block]	Components of Net Periodic Benefit Cost Pension Benefits Other Postretirement Benefits Millions of dollars 2015 2014 2013 2015 2014 2013 Service cost $ 19.3 $ 16.0 $ 17.6 $ 4.4 $ 3.6 $ 4.6 Interest cost 32.2 34.1 32.6 9.4 9.4 8.7 Expected return on assets (52.2 ) (56.3 ) (51.9 ) n/a n/a n/a Prior service cost amortization 3.4 3.5 5.0 0.3 0.3 0.6 Amortization of actuarial losses 11.4 4.0 14.3 1.7 — 2.6 Curtailment — — 8.4 — — — Net periodic benefit cost $ 14.1 $ 1.3 $ 26.0 $ 15.8 $ 13.3 $ 16.5
Schedule of Defined Benefit Plan Amounts Recognized in Other Comprehensive Income (Loss) [Table Text Block]	Other changes in plan assets and benefit obligations recognized in OCI (net of tax) were as follows: Pension Benefits Other Postretirement Benefits Millions of dollars 2015 2014 2013 2015 2014 2013 Current year actuarial (gain) loss $ 0.2 $ 0.2 $ (0.8 ) $ (0.3 ) $ 0.4 $ (0.4 ) Amortization of actuarial losses (0.1 ) (0.1 ) (0.1 ) — — (0.1 ) Amortization of prior service cost (0.1 ) (0.1 ) — — — — Total recognized in OCI $ — $ — $ (0.9 ) $ (0.3 ) $ 0.4 $ (0.5 )
Schedule of defined benefit plan, Other changes in plan assets recognized in regulatory assets [Table Text Block]	Other changes in plan assets and benefit obligations recognized in regulatory assets were as follows: Pension Benefits Other Postretirement Benefits Millions of dollars 2015 2014 2013 2015 2014 2013 Current year actuarial (gain) loss $ 12.2 $ 87.7 $ (137.1 ) $ (14.0 ) $ 15.8 $ (24.4 ) Amortization of actuarial losses (10.4 ) (3.5 ) (12.7 ) (1.5 ) — (2.2 ) Amortization of prior service cost (3.1 ) (2.8 ) (4.5 ) (0.3 ) (0.2 ) (0.5 ) Prior service cost (credit) — — (7.7 ) — — — Amortization of transition obligation — — — — — (0.1 ) Total recognized in regulatory assets $ (1.3 ) $ 81.4 $ (162.0 ) $ (15.8 ) $ 15.6 $ (27.2 )
Schedule of Assumptions Used in Determining Net Periodic Benefit Cost [Table Text Block]	Significant Assumptions Used in Determining Net Periodic Benefit Cost Pension Benefits Other Postretirement Benefits 2015 2014 2013 2015 2014 2013 Discount rate 4.20 % 5.03 % 4.10%/5.07% 4.30 % 5.19 % 4.19 % Expected return on plan assets 7.50 % 8.00 % 8.00 % n/a n/a n/a Rate of compensation increase 3.00 % 3.00 % 3.75%/3.00% 3.00 % 3.75 % 3.75 % Health care cost trend rate n/a n/a n/a 7.00 % 7.40 % 7.80 % 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 2020 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 2016 are as follows: Millions of Dollars Pension Benefits Other Postretirement Benefits Actuarial loss $ 11.2 $ 0.3 Prior service cost 3.0 0.2 Total $ 14.2 $ 0.5

COMMITMENTS AND CONTINGENCIES A

COMMITMENTS AND CONTINGENCIES ARO (Tables)	12 Months Ended
	Dec. 31, 2015
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: Millions of dollars 2015 2014 Beginning balance $ 563 $ 576 Liabilities incurred — 3 Liabilities settled (16 ) (6 ) Accretion expense 25 26 Revisions in estimated cash flows (52 ) (36 ) Ending balance $ 520 $ 563
SCE&G
Change in Asset Retirement Obligations [Line Items]
Change in Asset Retirement Obligations [Table Text Block]	follows: Millions of dollars 2015 2014 Beginning balance $ 536 $ 547 Liabilities incurred — 3 Liabilities settled (16 ) (6 ) Accretion expense 23 25 Revisions in estimated cash flows (55 ) (33 ) Ending Balance $ 488 $ 536

SEGMENT OF BUSINESS INFORMATI34

SEGMENT OF BUSINESS INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2015
Segment Reporting Information [Line Items]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	Electric Operations Gas Distribution Retail Gas Marketing Energy Marketing All Other Adjustments/ Eliminations Consolidated Total 2015 External Revenue $ 2,551 $ 810 $ 449 $ 569 $ 5 $ (4 ) $ 4,380 Intersegment Revenue 6 2 — 128 413 (549 ) — Operating Income 876 152 n/a 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 12 6 1 333 393 Net Income n/a n/a 19 9 185 533 746 Segment Assets 10,883 2,606 106 95 998 2,458 17,146 Expenditures for Assets 1,087 203 — 2 15 (154 ) 1,153 Deferred Tax Assets 5 29 9 6 — (49 ) — 2014 External Revenue $ 2,622 $ 1,012 $ 515 $ 786 $ 37 $ (21 ) $ 4,951 Intersegment Revenue 7 2 — 196 437 (642 ) — Operating Income 768 159 n/a 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 16 3 12 177 248 Net Income (Loss) n/a n/a 26 5 (6 ) 513 538 Segment Assets 10,182 2,487 140 150 1,474 2,385 16,818 Expenditures for Assets 936 200 — 2 52 (98 ) 1,092 Deferred Tax Assets 11 29 11 9 15 (75 ) — 2013 External Revenue $ 2,423 $ 942 $ 465 $ 652 $ 40 $ (27 ) $ 4,495 Intersegment Revenue 6 1 — 167 416 (590 ) — Operating Income 679 153 n/a n/a 27 51 910 Interest Expense 19 22 1 — 4 251 297 Depreciation and Amortization 297 70 3 — 26 (18 ) 378 Income Tax Expense 6 33 15 4 14 151 223 Net Income (Loss) n/a n/a 24 6 (2 ) 443 471 Segment Assets 9,488 2,340 172 133 1,378 1,616 15,127 Expenditures for Assets 907 140 — 1 31 27 1,106 Deferred Tax Assets 10 27 8 2 14 (61 ) —
SCE&G
Segment Reporting Information [Line Items]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	Disclosure of Reportable Segments (Millions of dollars) Electric Operations Gas Distribution Adjustments/ Eliminations Consolidated Total 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 ) — 2013 External Revenue $ 2,431 $ 414 — $ 2,845 Operating Income 679 58 — 737 Interest Expense 19 — $ 198 217 Depreciation and Amortization 294 26 (7 ) 313 Segment Assets 9,488 686 2,499 12,673 Expenditures for Assets 907 45 51 1,003 Deferred Tax Assets 10 n/a (10 ) —

DISPOSITIONS (Tables)

DISPOSITIONS (Tables)	12 Months Ended
	Dec. 31, 2015
Dispositions [Abstract]
Schedule of Disposal Groups [Table Text Block]	Millions of dollars CGT SCI Total Assets Held for Sale Utility Plant, Net $ 288.4 — $ 288.4 Nonutility Property and Investments, Net 0.6 $ 40.1 40.7 Current Assets 6.5 3.9 10.4 Deferred Debits and Other Assets 0.9 0.2 1.1 Total Assets Held for Sale $ 296.4 $ 44.2 $ 340.6 Liabilities Held for Sale Current Liabilities $ 3.5 $ 2.2 $ 5.7 Deferred Credits and Other Liabilities 42.9 3.1 46.0 Total Liabilities Held for Sale $ 46.4 $ 5.3 $ 51.7

QUARTERLY FINANCIAL INFORMATI36

QUARTERLY FINANCIAL INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2015
Statement [Line Items]
Schedule of Quarterly Financial Information [Table Text Block]	Millions of dollars, except per share amounts First Quarter Second Quarter Third Quarter Fourth Quarter Annual 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 2014 Total operating revenues $ 1,590 $ 1,026 $ 1,121 $ 1,214 $ 4,951 Operating income 350 154 269 234 1,007 Net income 193 96 144 105 538 Earnings per share 1.37 .68 1.01 .73 3.79
SCE&G
Statement [Line Items]
Schedule of Quarterly Financial Information [Table Text Block]	Millions of dollars First Quarter Second Quarter Third Quarter Fourth Quarter Annual 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 2014 Total operating revenues $ 859 $ 698 $ 812 $ 722 $ 3,091 Operating income 239 145 272 174 830 Net Income 126 99 157 76 458 Earnings Available to Common Shareholder 123 96 154 73 446

SUMMARY OF SIGNIFICANT ACCOUN37

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details)	12 Months Ended
	Dec. 31, 2015USD ($)MWshares	Dec. 31, 2014USD ($)shares	Dec. 31, 2013USD ($)shares	Dec. 31, 2012
Significant Accounting Policies
Effect of equity forward contracts, diluted earnings higher than basic earnings | shares			400,000
Unbilled Receivables, Current	$ 129,100,000	$ 186,400,000
Goodwill	$ 210,000,000	$ 210,000,000
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	2.61%	2.84%	2.93%
Public Utilities, Allowance for Funds Used During Construction, Additions	6.10%		7.20%	6.90%
Asset Management and Supply Service Agreements
Natural gas inventory, carrying amount		$ 26,100,000
Property, Plant and Equipment, Net	$ 280,000,000	$ 284,000,000
Accrual period of nuclear refueling charges (in months)	18
Earnings Per Share
Weighted Average Shares Outstanding - Basic | shares	142,900,000	141,900,000	138,700,000
Weighted Average Number of Shares Outstanding, Diluted | shares	142,900,000	141,900,000	139,100,000
SCEG and GENCO [Member]
Significant Accounting Policies
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	2.56%	2.84%	2.94%
SCE&G
Significant Accounting Policies
Maintenance Costs	$ 18,400,000
Environmental Remediation Costs Recognized in Regulatory Assets	34,800,000
Decommissioning Liability, Noncurrent	$ 696,800,000
Decommissioning safe storage	60
Unbilled Receivables, Current	$ 101,500,000	$ 115,800,000
Utilities Operating Expense, Maintenance	16,500,000	19,400,000
Anount accrued monthly for nuclear fuel outages			$ 1,400,000
Nuclear refueling outage cost	$ 40,200,000	$ 43,700,000
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	2.55%	2.85%	2.96%
Public Utilities, Allowance for Funds Used During Construction, Additions	5.60%	6.50%	6.90%
Asset Management and Supply Service Agreements
Property, Plant and Equipment, Net	$ 68,000,000	$ 67,000,000
Payments to Acquire Investments to be Held in Decommissioning Trust Fund	$ 3,200,000
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%
Asset Management and Supply Service Agreements
Property, Plant and Equipment, Net	$ 491,000,000
CGT [Member]
Significant Accounting Policies
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	0.00%	2.11%	2.19%
PSNC Energy
Significant Accounting Policies
Goodwill	$ 210,000,000
Accumulated Amortization and Write-down, Goodwill	$ 230,000,000
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	2.94%	2.98%	3.01%
Asset Management and Supply Service Agreements
Percentage of natural gas inventory held by counterparties under asset management and supply service agreements (as a percent)	46.00%	48.00%
Natural gas inventory, carrying amount	$ 17,700,000
Summer Station Unit 1 [Domain]
Significant Accounting Policies
Jointly Owned Utility Plant, Proportionate Ownership Share	66.70%	66.70%
Asset Management and Supply Service Agreements
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	$ 1,200,000,000	$ 1,200,000,000
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	620,400,000	578,300,000
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	214,600,000	199,300,000
Summer Station Unit 1 [Domain] | SCE&G
Asset Management and Supply Service Agreements
Accounts Receivable, Net	$ 178,800,000	$ 88,900,000
Summer Station New Units [Domain]
Significant Accounting Policies
Jointly Owned Utility Plant, Proportionate Ownership Share	55.00%	55.00%
Asset Management and Supply Service Agreements
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	$ 3,400,000,000	$ 2,700,000,000
SCE&G
Significant Accounting Policies
Nuclear refueling outage cost	$ 26,800,000	$ 29,100,000
Jointly Owned Utility Plant, Proportionate Ownership Share	5.00%
Debt issuance costs [Member]
Significant Accounting Policies
Debt Issuance Cost	$ 34,000,000
Debt issuance costs [Member] | SCE&G
Significant Accounting Policies
Debt Issuance Cost	29,000,000
Deferred tax asset or liability [Member]
Significant Accounting Policies
Debt Issuance Cost	65,500,000
Deferred tax asset or liability [Member] | SCE&G
Significant Accounting Policies
Debt Issuance Cost	$ 27,900,000

RATE AND OTHER REGULATORY MAT38

RATE AND OTHER REGULATORY MATTERS RATE AND OTHER REGULATORY MATTERS (Details)	3 Months Ended	9 Months Ended	12 Months Ended
	Mar. 31, 2014USD ($)	Sep. 30, 2015	Dec. 31, 2015USD ($)MW$ / shares	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Undercollected fuel balance reduction pursuant to SCPSC order					$ 41,600,000
Public Utilities Percentage Change in Retail Electric Rates Approved under BLRA			2.60%	2.80%	2.90%
Public Utilties increase (decrease) in retail electric rates			$ 64,500,000	$ 66,200,000	$ 67,200,000
Demand Side Management Program Costs, Noncurrent			$ 32,000,000	15,400,000	16,900,000
Capacity of renewable energy facilities by 2020 | MW			80
Capacity of renewable energy facilities by 2016 | MW			30
Depreciation Study 2015, Effect Of Lower Depreciation Rates Annually, Dollars			$ 29,000,000
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			$ 14,500,000
Depreciation Study 2015, Undercollected Fuel Amount Offset by Lower Depreciation Rates, Per Share | $ / shares			$ 0.06
Depreciation Study 2015, Increase in Net Income			$ 9,800,000
Prior accrual of under collected fuel					8,500,000
Gain (Loss) on Sale of Derivatives					8,500,000
DSM Programs SCPSC January 2016 filing, costs and net lost revenues recovery			$ 37,600,000
SCE&G
Public Utilities, Authorized Allowable Return on Common Equity, Percentage		0.00%	11.00%
Derivative, Gain on Derivative				$ 17,800,000
Undercollected fuel balance reduction pursuant to SCPSC order					$ 41,600,000
Fuel Cost Increase To Base Fuel Costs			$ 10,300,000
Public Utilities Percentage Change in Retail Electric Rates Approved under BLRA			2.60%	2.80%	2.90%
Public Utilties increase (decrease) in retail electric rates			$ 64,500,000	$ 66,200,000	$ 67,200,000
Deferred Amounts Applied To Undercollected Fuel Balance			46,000,000
Demand Side Management Program Costs, Noncurrent			$ 32,000,000	15,400,000	16,900,000
Capacity of renewable energy facilities by 2020 | MW			80
Capacity of renewable energy facilities by 2016 | MW			30
Prior accrual of under collected fuel					8,500,000
Gain (Loss) on Sale of Derivatives					$ 8,500,000
Carrying costs on deferred income tax assets			$ 9,500,000	5,800,000
Storm Damage Reserve Cost Applied				$ 5,000,000
Interest Rate Cash Flow Hedge Gain (Loss) Reclassified to Earnings, Net	$ 5,000,000
DSM Programs SCPSC January 2016 filing, costs and net lost revenues recovery			$ 37,600,000
DSM Programs [Member]
Regulatory Asset, Amortization Period			5 years
DSM Programs [Member] | SCE&G
Regulatory Asset, Amortization Period			5 years
Deferred Income Tax Charge [Member]
Regulatory Asset, Amortization Period			85 years
Deferred Income Tax Charge [Member] | SCE&G
Regulatory Asset, Amortization Period			85 years
Pension Costs [Member] | SCE&G
Regulatory Asset, Amortization Period			12 years		14 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
Asset Retirement Obligation Costs [Member] | SCE&G
Regulatory Asset, Amortization Period			110 years
Pension Plan, Defined Benefit | Other Regulatory Assets [Member] | SCE&G
Regulatory Asset, Amortization Period			30 years

RATE AND OTHER REGULATORY MAT39

RATE AND OTHER REGULATORY MATTERS ELECTRIC-BLRA (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Regulated Operations [Abstract]
Public Utilities Percentage Change in Retail Electric Rates Approved under BLRA	2.60%	2.80%	2.90%
Entity Information [Line Items]
Public Utilties increase (decrease) in retail electric rates	$ 64.5	$ 66.2	$ 67.2
SCE&G
Regulated Operations [Abstract]
Public Utilities Percentage Change in Retail Electric Rates Approved under BLRA	2.60%	2.80%	2.90%
Entity Information [Line Items]
Public Utilties increase (decrease) in retail electric rates	$ 64.5	$ 66.2	$ 67.2

RATE AND OTHER REGULATORY MAT40

RATE AND OTHER REGULATORY MATTERS GAS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2012
Entity Information [Line Items]
Public Utilities, Percent Increase (Decrease) in Retail Natural Gas Rates		0.60%
Public Utilities changes in Retail Natural Gas Rates Approved under RSA		$ 2.6
SCE&G
Entity Information [Line Items]
Public Utilities, Percent Increase (Decrease) in Retail Natural Gas Rates		0.60%
Public Utilities changes in Retail Natural Gas Rates Approved under RSA	$ 0	$ 2.6	$ 0

REGULATORY ASSETS AND LIABILITI

REGULATORY ASSETS AND LIABILITIES(Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2013	Dec. 31, 2014
Regulatory Assets, Noncurrent	$ 1,937	$ 1,823	$ 1,823
Regulatory Liability, Noncurrent	855		814
Asset Retirement Obligation Costs [Member]
Regulatory Liability, Noncurrent	732		703
Deferred gains on interest rate derivatives [Member]
Regulatory Liability, Noncurrent	96		82
Other Regulatory Liability [Member]
Regulatory Liability, Noncurrent	27		29
Demand Side Management programs [Member]
Regulatory Assets, Noncurrent	$ 61		56
Deferred Income Tax Charge [Member]
Regulatory Asset, Amortization Period	85 years
Regulatory Assets, Noncurrent		284	298
Asset Retirement Obligation Costs [Member]
Regulatory Asset, Amortization Period	110 years
Regulatory Assets, Noncurrent		366	405
Pension Costs [Member]
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority	$ 14	63
Regulatory Assets, Noncurrent		350	325
Deferred Losses On Interest Rate Derivatives [Member]
Regulatory Assets, Noncurrent		453	535
Canadys Refined Coal [Member]
Regulatory Assets, Noncurrent			127
Environmental Restoration Costs [Member]
MPG environmental remediation	24
Regulatory Assets, Noncurrent	$ 42		40
DSM Programs [Member]
Regulatory Asset, Amortization Period	5 years
Other Regulatory Assets [Member]
Regulatory Assets, Noncurrent	$ 144		137
SCE&G
Regulatory Assets, Noncurrent	1,857	1,745	1,745
Regulatory Liability, Noncurrent	635		610
SCE&G | Asset Retirement Obligation Costs [Member]
Regulatory Liability, Noncurrent	519		505
SCE&G | Deferred gains on interest rate derivatives [Member]
Regulatory Liability, Noncurrent	96		82
SCE&G | Other Regulatory Liability [Member]
Regulatory Liability, Noncurrent	20		23
SCE&G | Demand Side Management programs [Member]
Regulatory Assets, Noncurrent	$ 61		56
SCE&G | Deferred Income Tax Charge [Member]
Regulatory Asset, Amortization Period	85 years
Regulatory Assets, Noncurrent		278	291
SCE&G | Asset Retirement Obligation Costs [Member]
Regulatory Asset, Amortization Period	110 years
Regulatory Assets, Noncurrent		$ 347	384
SCE&G | Pension Costs [Member]
Regulatory Asset, Amortization Period	12 years	14 years
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority	$ 14	$ 63
Regulatory Assets, Noncurrent		310	295
SCE&G | Deferred Losses On Interest Rate Derivatives [Member]
Regulatory Assets, Noncurrent	535	453
SCE&G | Canadys Refined Coal [Member]
Regulatory Assets, Noncurrent		137	127
SCE&G | Environmental Restoration Costs [Member]
Regulatory Assets, Noncurrent	$ 35		36
SCE&G | DSM Programs [Member]
Regulatory Asset, Amortization Period	5 years
SCE&G | Other Regulatory Assets [Member]
Regulatory Assets, Noncurrent		$ 128	$ 129
Pension Plan, Defined Benefit | SCE&G | Other Regulatory Assets [Member]
Regulatory Asset, Amortization Period	30 years

RATE AND OTHER REGULATORY MAT42

RATE AND OTHER REGULATORY MATTERS NARRATIVE (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2013
Deferred Income Tax Charge [Member]
Regulatory Asset, Amortization Period	85 years
Asset Retirement Obligation Costs [Member]
Regulatory Asset, Amortization Period	110 years
Pension Costs [Member]
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority	$ 14	$ 63
SCE&G | Deferred Income Tax Charge [Member]
Regulatory Asset, Amortization Period	85 years
SCE&G | Asset Retirement Obligation Costs [Member]
Regulatory Asset, Amortization Period	110 years
SCE&G | Pension Costs [Member]
Regulatory Asset, Amortization Period	12 years	14 years
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority	$ 14	$ 63

COMMON EQUITY (Details)

COMMON EQUITY (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule of Capitalization, Equity [Line Items]
Common Stock, Shares Authorized	200,000,000	200,000,000
Proceeds from exercise of equity forward sales agreements			$ 196.2
Common stock issued through various compensation and dividend reinvestment plans, including the Stock Purchase Savings Plan	$ 14.3	$ 99.3	$ 100.9
Number of shares underlying forward sales contracts (in shares)			6,600,000
SCE&G
Schedule of Capitalization, Equity [Line Items]
Retained Earnings, Appropriated	$ 72.4	$ 67.7
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 DEBT44

LONG-TERM AND SHORT-TERM DEBT (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Long-term Debt Current Maturities in Next Twelve Months	$ 116
Medium-term Notes	800	$ 800
Senior Notes	84	88
First Mortgage Bonds	4,340	3,840
GENCO Notes	220	227
Industrial and Pollution Control Bonds	122	122
Senior Notes, Noncurrent	350	350
Long Term Contract for Nuclear Fuel Purchase	100	100
Other Long-term Debt	18	167
Long-term Debt, Gross	6,034	5,694
Long-term Debt, Current Maturities	(116)	(166)
Debt Instrument, Unamortized Discount	0	3
Unamortized Debt Issuance Expense	(36)	(34)
Long-term Debt	5,882	$ 5,497
Long-term Debt, Maturities, Repayments of Principal in Year Two	15
Long-term Debt, Maturities, Repayments of Principal in Year Three	724
Long-term Debt, Maturities, Repayments of Principal in Year Four	13
Long-term Debt, Maturities, Repayments of Principal in Year Five	$ 363
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
Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	1.11%	0.93%
Debt Instrument, Redemption Period, Start Date	Jun. 1, 2016
Debt Instrument, Redemption Period, End Date	Jun. 1, 2034
Long-term Debt, Percentage Bearing Fixed Interest, Percentage Rate		6.17%
First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	5.78%	5.56%
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	5.92%	5.90%
Debt Instrument, Redemption Period, Start Date	Feb. 1, 2016
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	0.03%	0.04%
Senior Debentures [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	5.93%	5.93%
Debt Instrument, Redemption Period, Start Date	Mar. 30, 2020
Debt Instrument, Redemption Period, End Date	Dec. 15, 2026
Nuclear fuel purchase contract [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	0.78%	0.78%
Debt Instrument, Redemption Period, End Date	Nov. 1, 2016
Other Debt [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	2.72%	7.39%
Debt Instrument, Redemption Period, Start Date	Jan. 1, 2016
Debt Instrument, Redemption Period, End Date	Sep. 30, 2027
SCE&G
Debt Instrument [Line Items]
Debt Instrument, Interest Rate Terms	0.051	0.045
Proceeds from Issuance of First Mortgage Bond	$ 500	$ 300
Long-term Debt Current Maturities in Next Twelve Months	110
First Mortgage Bonds	4,340	3,840
GENCO Notes	220	227
Industrial and Pollution Control Bonds	122	122
Long Term Contract for Nuclear Fuel Purchase	100	100
Other Long-term Debt	17	14
Long-term Debt, Gross	4,799	4,303
Long-term Debt, Current Maturities	(110)	(10)
Debt Instrument, Unamortized Discount	2	6
Unamortized Debt Issuance Expense	(32)	(29)
Long-term Debt	4,659	$ 4,270
Long-term Debt, Maturities, Repayments of Principal in Year Two	10
Long-term Debt, Maturities, Repayments of Principal in Year Three	720
Long-term Debt, Maturities, Repayments of Principal in Year Four	9
Long-term Debt, Maturities, Repayments of Principal in Year Five	$ 8
SCE&G | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	5.78%	5.56%
Debt Instrument, Redemption Period, Start Date	Nov. 1, 2018
Debt Instrument, Redemption Period, End Date	Jun. 1, 2065
SCE&G | Genco Notes [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	5.92%	5.90%
Debt Instrument, Redemption Period, Start Date	Feb. 1, 2016
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, Start Date	Feb. 1, 2028
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	0.78%	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	2.63%	2.63%
Debt Instrument, Redemption Period, Start Date	Jan. 31, 2016
Debt Instrument, Redemption Period, End Date	Sep. 30, 2027

LONG-TERM AND SHORT-TERM DEBT45

LONG-TERM AND SHORT-TERM DEBT (Details 2) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument, Redemption [Line Items]
Short-term Debt, Weighted Average Interest Rate	0.74%	0.52%
Line of Credit Facility, Maximum Borrowing Capacity	$ 1,400,000,000	$ 1,400,000,000
Commercial Paper	420,000,000	709,000,000
Letters of Credit Outstanding, Amount	$ 300,000	300,000
Other Long-Term Debt Lenders	2
Long-term Debt Current Maturities in Next Twelve Months	$ 116,000,000
Long-term Debt, Maturities, Repayments of Principal in Year Two	15,000,000
Long-term Debt, Maturities, Repayments of Principal in Year Three	724,000,000
Long-term Debt, Maturities, Repayments of Principal in Year Four	13,000,000
Long-term Debt, Maturities, Repayments of Principal in Year Five	363,000,000
Line of Credit Facility, Remaining Borrowing Capacity	$ 980,000,000	$ 691,000,000
Industrial and Pollution Control Bonds [Member]
Debt Instrument, Redemption [Line Items]
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate	0.03%	0.04%
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, TD Bank, Credit Suisse AG,Cayman Islands Branch, MUFG Union Bank and UBS Loan [Member]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	7.90%
BB&T Bank [Domain]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	5.50%
SCE&G | Branch Banking Trust Company, Union Bank and US Bank National Assoc [Member]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank	5.50%
PSNC Energy [Member]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 200,000,000	$ 100,000,000
Parent Company [Member]
Debt Instrument, Redemption [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 400,000,000	$ 300,000,000
Expires December 2020 [Domain]
Debt Instrument, Redemption [Line Items]
Duration of Long Term Credit Agreement	5
Long-Term Line of Credit - SCE&G (including SC Fuel Co)	$ 1,200,000,000
Long-Term Line of Credit - SC Fuel Co only	$ 500,000,000
Expires December 2016 [Domain]
Debt Instrument, Redemption [Line Items]
Duration of Long Term Credit Agreement	3	3
Long-term Line of Credit - SCE&G only	$ 200,000,000
Parent Company [Member]
Debt Instrument, Redemption [Line Items]
Short-term Debt, Weighted Average Interest Rate	1.19%	0.54%
Commercial Paper	$ 37,000,000	$ 179,000,000
Letters of Credit Outstanding, Amount	3,000,000	3,000,000
Line of Credit Facility, Remaining Borrowing Capacity	$ 360,000,000	$ 118,000,000
PSNC Energy [Member]
Debt Instrument, Redemption [Line Items]
Short-term Debt, Weighted Average Interest Rate	0.77%	0.65%
Commercial Paper	$ 74,000,000	$ 30,000,000
Line of Credit Facility, Remaining Borrowing Capacity	$ 126,000,000	$ 70,000,000

LONG-TERM AND SHORT-TERM DEBT46

LONG-TERM AND SHORT-TERM DEBT (NARRATIVE) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Debt Instrument [Line Items]
Line of Credit, Current	$ 150
months preceding issuance of bonds	18
Unfunded property additions	70.00%
Consecutive months for bond ratio	12
Bond Ratio	5.17
SCE&G
Debt Instrument [Line Items]
Due to Related Parties	$ 33	$ 83
Related Party Transaction, Due from (to) Related Party, Current	$ 9	$ 80
months preceding issuance of bonds	18
Unfunded property additions	70.00%
Consecutive months for bond ratio	12
Bond Ratio	5.17

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($)	3 Months Ended								9 Months Ended	12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Sep. 30, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Investments, Owned, Federal Income Tax Note [Line Items]
Deferred Tax Asset, Deferred Fuel Cost	$ 8,000,000									$ 8,000,000
Income Available to Common Shareholders	98,000,000	$ 149,000,000	$ 99,000,000	$ 400,000,000	$ 105,000,000	$ 144,000,000	$ 96,000,000	$ 193,000,000		$ 746,000,000	$ 538,000,000	$ 471,000,000
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent					6.00%				6.90%	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)										$ 382,000,000	38,000,000	161,000,000
Current State and Local Tax Expense (Benefit)										57,000,000	(4,000,000)	17,000,000
Current Income Tax Expense (Benefit)										439,000,000	34,000,000	178,000,000
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred Federal Income Tax Expense (Benefit)										36,000,000	(184,000,000)	(39,000,000)
Deferred State and Local Income Tax Expense (Benefit)										7,000,000	(34,000,000)	(10,000,000)
Deferred Income Tax Expense (Benefit)										43,000,000	(218,000,000)	(49,000,000)
Income Tax Reconciliation, Tax Credits, Investment [Abstract]
Amortization of Amounts Deferred Under State and Local Investment Tax Credits										(1,000,000)	(1,000,000)	(1,000,000)
Investment Tax Credit										(3,000,000)	(4,000,000)	(4,000,000)
Income Tax Expense (Benefit)										393,000,000	248,000,000	223,000,000
Income (Loss) from Continuing Operations before Income Taxes, Domestic										1,139,000,000	786,000,000	694,000,000
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount										399,000,000	275,000,000	243,000,000
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount										38,000,000	24,000,000	22,000,000
Income Tax Reconciliation, Amortization of State and Local Investment Tax Credits										(6,000,000)	(5,000,000)	(5,000,000)
Income Tax Reconciliation, Allowance for Cost of Equity Funds Used During Construction										(9,000,000)	(11,000,000)	(9,000,000)
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)	(3,000,000)	(3,000,000)
Section41TaxCredit										(1,000,000)	(3,000,000)	0
Section 45 tax credit										(9,000,000)	(9,000,000)	(5,000,000)
Effective Income Tax Rate Reconciliation, Deduction, Qualified Production Activity, Percent										(18,000,000)	(7,000,000)	(11,000,000)
Income Tax Reconciliation, Sale of Subsidiaries										7,000,000
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount										2,000,000	(3,000,000)	1,000,000
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Accrued Liabilities	135,000,000				$ 127,000,000					135,000,000	127,000,000
Deferred tax Nuclear Decommissioning	199,000,000				216,000,000					199,000,000	216,000,000
Deferred Tax Assets, Financial Instruments	35,000,000				40,000,000					35,000,000	40,000,000
Deferred Tax Asset, Unamortized Investment, Tax Credits	16,000,000				17,000,000					16,000,000	17,000,000
Deferred Tax Assets, Monetization of Bankruptcy Claims	0				10,000,000					0	10,000,000
Deferred Tax Assets, Other	5,000,000				10,000,000					5,000,000	10,000,000
Deferred Tax Assets, Net	398,000,000				420,000,000					398,000,000	420,000,000
Deferred Tax Liabilities, Property, Plant and Equipment	1,906,000,000				1,928,000,000					1,906,000,000	1,928,000,000
Deferred Tax Liabilities, Tax Deferred Expense Compensation and Benefits, Employee Benefits	96,000,000				107,000,000					96,000,000	107,000,000
Deferred Tax Liabilities, Asset Retirement Obligation	135,000,000				122,000,000					135,000,000	122,000,000
Deferred Tax Liabilities, Deferred Expense Fuel Costs	0				27,000,000					0	27,000,000
Deferred tax asset unrecovered plant	49,000,000				53,000,000					49,000,000	53,000,000
Deferred Tax Liabilities, Derivatives	0				21,000,000					0	21,000,000
Deferred Tax Liability, Demand Side Management	23,000,000				21,000,000					23,000,000	21,000,000
deferred tax liability, prepayments	31,000,000				27,000,000					31,000,000	27,000,000
Deferred Tax Liabilities, Other	65,000,000				45,000,000					65,000,000	45,000,000
Deferred Tax Liabilities, Net	2,305,000,000				2,351,000,000					2,305,000,000	2,351,000,000
Deferred Tax Liabilities, Net, Noncurrent	1,907,000,000				1,931,000,000					1,907,000,000	1,931,000,000
Unrecognized Tax Benefits	49,000,000				16,000,000					49,000,000	16,000,000	3,000,000
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions										2,000,000
SCE&G
Investments, Owned, Federal Income Tax Note [Line Items]
Decrease in Unrecognized Tax Benefits is Reasonably Possible	8,000,000									8,000,000
Deferred Tax Asset, Deferred Fuel Cost	7,000,000									7,000,000
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	17,000,000									17,000,000
Increase in Unrecognized Tax Benefits is Reasonably Possible	7,000,000									$ 7,000,000
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)										$ 208,000,000	39,000,000	146,000,000
Current State and Local Tax Expense (Benefit)										32,000,000	(6,000,000)	13,000,000
Current Income Tax Expense (Benefit)										240,000,000	33,000,000	159,000,000
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred Federal Income Tax Expense (Benefit)										(3,000,000)	(157,000,000)	(25,000,000)
Deferred State and Local Income Tax Expense (Benefit)										(3,000,000)	(32,000,000)	(9,000,000)
Deferred Income Tax Expense (Benefit)										(6,000,000)	(189,000,000)	(34,000,000)
Income Tax Reconciliation, Tax Credits, Investment [Abstract]
Amortization of Amounts Deferred Under State and Local Investment Tax Credits										(1,000,000)	(1,000,000)	(1,000,000)
Investment Tax Credit										(3,000,000)	(4,000,000)	(4,000,000)
Income Tax Expense (Benefit)										231,000,000	218,000,000	189,000,000
Net Income (Loss) Attributable to Noncontrolling Interest										14,000,000	12,000,000	11,000,000
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount										249,000,000	237,000,000	203,000,000
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount										24,000,000	21,000,000	18,000,000
Income Tax Reconciliation, Amortization of State and Local Investment Tax Credits										(6,000,000)	(5,000,000)	(5,000,000)
Income Tax Reconciliation, Allowance for Cost of Equity Funds Used During Construction										(9,000,000)	(10,000,000)	(9,000,000)
Amortization of Amounts Deferred under Federal Investment Tax Credits										(2,000,000)	(3,000,000)	(3,000,000)
Section 45 tax credit										(9,000,000)	(9,000,000)	(5,000,000)
Effective Income Tax Rate Reconciliation, Deduction, Qualified Production Activity, Percent										(18,000,000)	(7,000,000)	(11,000,000)
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount										1,000,000	(3,000,000)	1,000,000
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Accrued Liabilities	52,000,000				47,000,000					52,000,000	47,000,000
Deferred tax Nuclear Decommissioning	187,000,000				205,000,000					187,000,000	205,000,000
Deferred Tax Assets, Financial Instruments	2,000,000									2,000,000
Deferred Tax Asset, Unamortized Investment, Tax Credits	16,000,000				17,000,000					16,000,000	17,000,000
Deferred Tax Assets, Other	2,000,000				6,000,000					2,000,000	6,000,000
Deferred Tax Assets, Net	266,000,000				275,000,000					266,000,000	275,000,000
Deferred Tax Liabilities, Property, Plant and Equipment	1,644,000,000				1,623,000,000					1,644,000,000	1,623,000,000
Deferred Tax Liabilities, Tax Deferred Expense Compensation and Benefits, Employee Benefits	85,000,000				91,000,000					85,000,000	91,000,000
Deferred Tax Liabilities, Asset Retirement Obligation	127,000,000				115,000,000					127,000,000	115,000,000
Deferred Tax Liabilities, Deferred Expense Fuel Costs	0				27,000,000					0	27,000,000
Deferred tax asset unrecovered plant	49,000,000				53,000,000					49,000,000	53,000,000
Deferred Tax Liabilities, Derivatives	0				21,000,000					0	21,000,000
Deferred Tax Liability, Demand Side Management	23,000,000				21,000,000					23,000,000	21,000,000
deferred tax liability, prepayments	29,000,000				25,000,000					29,000,000	25,000,000
Deferred Tax Liabilities, Other	41,000,000				23,000,000					41,000,000	23,000,000
Deferred Tax Liabilities, Net	1,998,000,000				1,999,000,000					1,998,000,000	1,999,000,000
Deferred Tax Liabilities, Net, Noncurrent	1,732,000,000				1,724,000,000					1,732,000,000	1,724,000,000
Unrecognized Tax Benefits	$ 49,000,000				$ 16,000,000					49,000,000	16,000,000	3,000,000	$ 0
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions										33,000,000	0	0
Unrecognized Tax Benefits, Decrease Resulting from Prior Period Tax Positions										(2,000,000)	0	0
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions										$ 2,000,000	$ 13,000,000	$ 3,000,000

INCOME TAXES INCOME TAXES (Deta

INCOME TAXES INCOME TAXES (Details 2) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
income tax [Line Items]
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Accrued Liabilities	$ 135,000,000	$ 127,000,000
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Income Tax Reconciliation, Income Tax Expense (Benefit), at Federal Statutory Income Tax Rate	399,000,000	275,000,000	$ 243,000,000
Income Tax Expense (Benefit) Continuing Operations, Income Tax Reconciliation, Changes [Abstract]
Income Tax Reconciliation, State and Local Income Taxes	38,000,000	24,000,000	22,000,000
Income Tax Reconciliation, Amortization of State and Local Investment Tax Credits	(6,000,000)	(5,000,000)	(5,000,000)
Income Tax Reconciliation, Allowance for Cost of Equity Funds Used During Construction	(9,000,000)	(11,000,000)	(9,000,000)
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	3,000,000	3,000,000
Section 45 tax credit	9,000,000	9,000,000	5,000,000
Income Tax Reconciliation, Other Adjustments	2,000,000	(3,000,000)	1,000,000
Income Tax Expense (Benefit)	393,000,000	248,000,000	223,000,000
Income (Loss) from Continuing Operations before Income Taxes, Domestic	1,139,000,000	786,000,000	694,000,000
SCE&G
income tax [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	49,000,000
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Accrued Liabilities	52,000,000	47,000,000
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Income Tax Reconciliation, Income Tax Expense (Benefit), at Federal Statutory Income Tax Rate	249,000,000	237,000,000	203,000,000
Income Tax Expense (Benefit) Continuing Operations, Income Tax Reconciliation, Changes [Abstract]
Income Tax Reconciliation, State and Local Income Taxes	24,000,000	21,000,000	18,000,000
Income Tax Reconciliation, Amortization of State and Local Investment Tax Credits	(6,000,000)	(5,000,000)	(5,000,000)
Income Tax Reconciliation, Allowance for Cost of Equity Funds Used During Construction	(9,000,000)	(10,000,000)	(9,000,000)
Amortization of Amounts Deferred under Federal Investment Tax Credits	2,000,000	3,000,000	3,000,000
Section 45 tax credit	9,000,000	9,000,000	5,000,000
Income Tax Reconciliation, Other Adjustments	1,000,000	(3,000,000)	1,000,000
Income Tax Expense (Benefit)	231,000,000	218,000,000	189,000,000
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest	$ 711,000,000	$ 676,000,000	$ 580,000,000

INCOME TAXES INCOME TAXES (De49

INCOME TAXES INCOME TAXES (Details 3) - USD ($) $ in Millions	12 Months Ended
	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	$ 135	$ 127
Deferred tax Nuclear Decommissioning	199	216
Deferred Tax Assets, Financial Instruments	35	40
Deferred Tax Asset, Unamortized Investment, Tax Credits	16	17
Deferred Tax Asset, Deferred Fuel Cost	8
Deferred Tax Assets, Monetization of Bankruptcy Claims	0	10
Deferred Tax Liabilities, Tax Deferred Expense Compensation and Benefits, Employee Benefits	96	107
Deferred Tax Assets, Other	5	10
Deferred Tax Assets, Net	398	420
Deferred Tax Liabilities, Gross [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment	1,906	1,928
Deferred Tax Liabilities, Asset Retirement Obligation	135	122
Deferred Tax Liabilities, Deferred Expense Fuel Costs	0	27
Deferred tax asset unrecovered plant	49	53
Deferred Tax Liabilities, Derivatives	0	21
Deferred Tax Liability, Demand Side Management	23	21
deferred tax liability, prepayments	31	27
Deferred Tax Liabilities, Other	65	45
Deferred Tax Liabilities, Gross	2,305	2,351
Deferred Tax Liabilities, Net, Noncurrent	1,907	1,931
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Gross increases current period tax positions	2
Balance at the end of the period	49	16	$ 3
SCE&G
Investments, Owned, Federal Income Tax Note [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	49
Deferred Tax Assets, Net [Abstract]
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Accrued Liabilities	52	47
Deferred tax Nuclear Decommissioning	187	205
Deferred Tax Assets, Financial Instruments	2
Deferred Tax Asset, Unamortized Investment, Tax Credits	16	17
Deferred Tax Asset, Deferred Fuel Cost	7
Deferred Tax Liabilities, Tax Deferred Expense Compensation and Benefits, Employee Benefits	85	91
Deferred Tax Assets, Other	2	6
Deferred Tax Assets, Net	266	275
Deferred Tax Liabilities, Gross [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment	1,644	1,623
Deferred Tax Liabilities, Asset Retirement Obligation	127	115
Deferred Tax Liabilities, Deferred Expense Fuel Costs	0	27
Deferred tax asset unrecovered plant	49	53
Deferred Tax Liabilities, Derivatives	0	21
Deferred Tax Liability, Demand Side Management	23	21
deferred tax liability, prepayments	29	25
Deferred Tax Liabilities, Other	41	23
Deferred Tax Liabilities, Gross	1,998	1,999
Deferred Tax Liabilities, Net, Noncurrent	1,732	1,724
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions	33	0	0
Gross decreases tax positions in prior period	(2)	0	0
Gross increases current period tax positions	2	13	3
Balance at the end of the period	$ 49	$ 16	$ 3

DERIVATIVE FINANCIAL INSTRUME50

DERIVATIVE FINANCIAL INSTRUMENTS (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)MMBTU		Dec. 31, 2014USD ($)MMBTU
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	58,229,980	[1]	55,733,059	[2]
Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	7,530,000		6,840,000
Retail Gas Marketing
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	7,869,000		7,951,000
Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	42,830,980	[1]	40,942,059	[2]
Energy Related Derivative [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	38,857,480	[1]	37,495,339	[2]
Energy Related Derivative [Member] | Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0		0
Energy Related Derivative [Member] | Retail Gas Marketing
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0		0
Energy Related Derivative [Member] | Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	38,857,480		37,495,339
Commodity Contracts
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	19,372,500		18,237,720
Commodity Contracts | Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	7,530,000		6,840,000
Commodity Contracts | Retail Gas Marketing
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	7,869,000		7,951,000
Commodity Contracts | Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	3,973,500		3,446,720
Basis Swap [Member] | Energy Related Derivative [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	1,842,048		933,893
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	$ 1,235		$ 1,085
Cash Flow Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	120		124.4
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	1,235		1,085
SCE&G | Cash Flow Hedging [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	$ 36.4		$ 36.4
[1]	(a) Includes an aggregate 1,842,048 MMBTU related to basis swap contracts in Energy Marketing.
[2]	(b) Includes an aggregate 933,893 MMBTU related to basis swap contracts in Energy Marketing.

DERIVATIVE FINANCIAL INSTRUME51

DERIVATIVE FINANCIAL INSTRUMENTS FAIR VALUE ON BALANCE SHEET (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Derivative Liability	$ 106	$ 289
Derivative Asset	30	21
Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	8	5
Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability	53	50
Other Current Assets [Member]
Derivative [Line Items]
Derivative Liability	3	6
Derivative Asset	22	16
Interest Rate Contract
Derivative [Line Items]
Derivative Liability	87	257
Derivative Asset	15
Commodity Contracts
Derivative [Line Items]
Derivative Liability	5	12
Derivative Asset	1	1
Other Energy Management Contract [Member]
Derivative [Line Items]
Derivative Liability	14	20
Derivative Asset	14	20
Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability	37	45
Designated as Hedging Instrument [Member] | Interest Rate Contract | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability	4	5
Designated as Hedging Instrument [Member] | Interest Rate Contract | Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability	28	28
Designated as Hedging Instrument [Member] | Commodity Contracts | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability	4	11
Designated as Hedging Instrument [Member] | Commodity Contracts | Other Current Assets [Member]
Derivative [Line Items]
Derivative Liability	1	1
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability	69	244
Derivative Asset	30	21
Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability	33	207
Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	5
Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability	22	17
Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset	10
Not Designated as Hedging Instrument [Member] | Commodity Contracts | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset	1	1
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability	9	10
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	3	5
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability	3	5
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Liability	2	5
Derivative Asset	11	15
SCE&G
Derivative [Line Items]
Derivative Liability	65	233
Derivative Asset	15
SCE&G | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	5
SCE&G | Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability	31	25
SCE&G | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset	10
SCE&G | Interest Rate Contract
Derivative [Line Items]
Derivative Liability	65	233
Derivative Asset	15
SCE&G | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability	10	9
SCE&G | Designated as Hedging Instrument [Member] | Interest Rate Contract | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability	1	1
SCE&G | Designated as Hedging Instrument [Member] | Interest Rate Contract | Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability	9	8
SCE&G | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability	55	224
Derivative Asset	15
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability	33	207
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	5
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability	22	$ 17
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset	$ 10

DERIVATIVE FINANCIAL INSTRUME52

DERIVATIVE FINANCIAL INSTRUMENTS ON INCOME STATEMENT (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative [Line Items]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	$ 12	$ 14	$ 7
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	$ (22)	$ (3)	$ (11)
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant	insignificant	insignificant
Interest Rate Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 7	$ 7	$ 8
Interest Rate Contract | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred	(7.1)
Commodity Contracts
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	15	(4)	3
Commodity Contracts | Gas Purchased for Resale [Member] [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred	(3.3)
Not Designated as Hedging Instrument [Member] | Interest Rate Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	(69)	(352)	39
Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Other Nonoperating Income (Expense) [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	$ 5	$ 64	$ 50
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
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	$ (69)	$ (352)	$ 39
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Other Nonoperating Income (Expense) [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	5	64	50
Cash Flow Hedging [Member] | Interest Rate Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	(2)	(6)	5
Cash Flow Hedging [Member] | Interest Rate Contract | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income Effective Portion, Net	(3)	(3)	(3)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(7)	(7)	(8)
Cash Flow Hedging [Member] | Commodity Contracts
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	(10)	(8)	2
Cash Flow Hedging [Member] | Commodity Contracts | Gas Purchased for Resale [Member] [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(15)	4	(3)
Cash Flow Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	(3)	(9)	106
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred	2.2
Cash Flow Hedging [Member] | Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred	0.6
Cash Flow Hedging [Member] | SCE&G | Interest Rate Contract | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income Effective Portion, Net	(3)	(3)	(3)
Cash Flow Hedging [Member] | SCE&G | Designated as Hedging Instrument [Member] | Interest Rate Contract | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	(3)	$ (9)	$ 106
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred	2.2
Cash Flow Hedging [Member] | SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred	$ 0.6

DERIVATIVE FINANCIAL INSTRUME53

DERIVATIVE FINANCIAL INSTRUMENTS (CREDIT RISK) (Details 3) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Derivative, Credit Risk Related Contingent Features [Abstract]
Collateral Already Posted, Aggregate Fair Value	$ 50.4	$ 152.4
Additional collateral required to be posted to counterparties if all underlying contingent features were fully triggered	44.8	129.8
Aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position	95.2	282.2
Cash collateral requested from counterparty	7.3
Derivative, net asset position	7.3
Letter of Credit Available Commodity Derivatives,asset position	3	9.2
Commodity Derivative, net asset position	14	20
SCE&G
Derivative, Credit Risk Related Contingent Features [Abstract]
Collateral Already Posted, Aggregate Fair Value	13.4	107.1
Additional collateral required to be posted to counterparties if all underlying contingent features were fully triggered	43.6	125.9
Aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position	57	233
Cash collateral requested from counterparty	7.3	0
Derivative, net asset position	$ 7.3	$ 0

DERIVATIVE FINANCIAL INSTRUME54

DERIVATIVE FINANCIAL INSTRUMENTS OFFSETTING ASSETS AND LIABILITIES (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Derivative Liability	$ 106	$ 289
Derivative Asset, Fair Value, Gross Liability	(1)	0
Derivative Assets, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments	(8)	0
Derivative Asset, Fair Value, Gross Asset	31	21
Derivative Liability, Fair Value, Gross Asset	(1)	0
Derivative Liabilities, Net Amount	48	137
Derivative Liability, Fair Value, Gross Liability	107	289
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments	(8)	0
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Cash Collateral Posted	(50)	(152)
Derivative Assets, Net Amount	22	21
Other Current Assets [Member]
Derivative [Line Items]
Derivative Liability	3	6
Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	50	233
Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability	53	50
Interest Rate Contract
Derivative [Line Items]
Derivative Liability	87	257
Derivative Asset, Fair Value, Gross Liability	0
Derivative Assets, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments	(8)
Derivative Asset, Fair Value, Gross Asset	15
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liabilities, Net Amount	43	126
Derivative Liability, Fair Value, Gross Liability	87	257
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments	(8)	0
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Cash Collateral Posted	(36)	(131)
Derivative Assets, Net Amount	7
Commodity Contracts
Derivative [Line Items]
Derivative Liability	5	12
Derivative Asset, Fair Value, Gross Liability	0
Derivative Assets, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments	0
Derivative Asset, Fair Value, Gross Asset	1	1
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liabilities, Net Amount	0	2
Derivative Liability, Fair Value, Gross Liability	5	12
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments	0	0
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Cash Collateral Posted	(5)	(10)
Derivative Assets, Net Amount	1	1
Other Energy Management Contract [Member]
Derivative [Line Items]
Derivative Liability	14	20
Derivative Asset, Fair Value, Gross Liability	(1)	0
Derivative Assets, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments	0
Derivative Asset, Fair Value, Gross Asset	15	20
Derivative Liability, Fair Value, Gross Asset	(1)	0
Derivative Liabilities, Net Amount	5	9
Derivative Liability, Fair Value, Gross Liability	15	20
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments	0	0
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Cash Collateral Posted	(9)	(11)
Derivative Assets, Net Amount	14	20
SCE&G
Derivative [Line Items]
Derivative Liability	65	233
SCE&G | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	34	208
SCE&G | Other Deferred Credits and Other Liabilities
Derivative [Line Items]
Derivative Liability	31	25
SCE&G | Interest Rate Contract
Derivative [Line Items]
Derivative Liability	65	233
Derivative Asset, Fair Value, Gross Liability	0
Derivative Assets, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments	(8)
Derivative, Collateral, Obligation to Return Cash	0
Derivative Asset, Fair Value, Gross Asset	15
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liabilities, Net Amount	44	126
Derivative Liability, Fair Value, Gross Liability	65	233
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments	(8)	0
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Cash Collateral Posted	(13)	$ (107)
Derivative Assets, Net Amount	$ 7

FAIR VALUE MEASUREMENTS, INCL55

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	$ 30	$ 21
Derivative Liability	$ 106	$ 289
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
Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale Securities	$ 11	$ 13
Interest Rate Contract
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	15
Derivative Liability	87	257
Interest Rate Contract | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	15	0
Derivative Liability	87	257
Commodity Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	1	1
Derivative Liability	5	12
Commodity Contracts | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	1	1
Derivative Liability	1	1
Commodity Contracts | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0
Derivative Liability	4	11
Other Energy Management Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	14	20
Derivative Liability	14	20
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]
Derivative Asset		0
Derivative Liability	4	5
Other Energy Management Contract [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	14	20
Derivative Liability	12	18
SCE&G
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	15
Derivative Liability	$ 65	$ 233
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
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	$ 15
Derivative Liability	65	$ 233
SCE&G | Interest Rate Contract | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	15	0
Derivative Liability	$ 65	$ 233

FAIR VALUE MEASUREMENTS, INCL56

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details 2) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	$ 30	$ 21
Other Long-term Debt, Noncurrent	5,997.6	5,663.1
Long-term debt, Fair Value	6,445.7	6,558
SCE&G
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	15
Other Long-term Debt, Noncurrent	4,769	4,279.5
Long-term debt, Fair Value	5,129.1	5,041.9
Interest Rate Contract
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	15
Interest Rate Contract | SCE&G
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	15
Interest Rate Contract | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	15	0
Interest Rate Contract | Fair Value, Inputs, Level 2 [Member] | SCE&G
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	$ 15	$ 0

EMPLOYEE BENEFIT PLANS (Details

EMPLOYEE BENEFIT PLANS (Details) - USD ($)	4 Months Ended	8 Months Ended	12 Months Ended
	Dec. 31, 2013	Aug. 31, 2013	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation				$ 829,300,000	$ 888,300,000
Defined Benefit Plan Health Care Cost Trend Rate, Assumed				7.00%
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	1,300,000
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation				700,000	1,000,000
Defined Benefit Plan, Fair Value of Plan Assets				$ 782,000,000	$ 862,000,000
Transfers of fair value amounts into or out of Levels 1, 2 or 3				no	no
Defined Contribution Plan, Cost Recognized				$ 26,200,000	$ 25,800,000	$ 23,400,000
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Adoption of new mortality tables in 2014, gain					3,000,000
Adoption of modified mortality tables in 2015, gain				2,400,000
Defined Benefit Plan, Benefit Obligation	$ 238,000,000			253,600,000	268,200,000	238,000,000
Service cost				5,300,000	4,600,000	5,900,000
Interest cost				11,400,000	12,000,000	$ 11,100,000
Defined Benefit Plan, Contributions by Plan Participants				2,400,000	2,200,000
Defined Benefit Plan, Actuarial Net (Gains) Losses				21,200,000	(23,500,000)
Defined Benefit Plan, Benefits Paid				$ (12,500,000)	$ (12,100,000)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate				4.78%	4.30%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase				3.00%	3.00%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate				5.00%	5.00%	5.00%
Defined Benefit Plan, Fair Value of Plan Assets				$ 0	$ 0
Defined Benefit Plan, Funded Status of Plan				(253,600,000)	(268,200,000)
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities				(11,900,000)	(11,200,000)
Other Postretirement Defined Benefit Plan, Liabilities, Noncurrent				(241,700,000)	(257,000,000)
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax				1,700,000	3,000,000
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Prior Service Cost (Credit), before Tax				0	100,000
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax				1,700,000	3,100,000
pension and other postretirement benefit plans, regulated assets, net gains, before tax				24,000,000	43,800,000
Pension and other postretirement benefit plans, regulatory assets, net prior service costs (credit), before tax				300,000	600,000
Pension and other postretirement benefit plans, regulatory assets, before tax				24,300,000	44,400,000
Defined Benefit Plan, Shared Costs Deferred				13.8	15.1
Regulatory assets, pension and other postretirement benefit plans, net unamortized gain (loss) arising during the period, net of tax				$ (18,000,000)	$ 19,400,000	$ (29,900,000)
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate				4.30%	5.19%	4.19%
Defined Benefit Plan, Amortization of Transition Obligations (Assets)				$ 0	$ 0	$ 300,000
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase				3.00%	3.75%	3.75%
Regulatory assets, amortization of actuarial losses, pension and other postretirement benefit plans, net of tax				$ (1,800,000)	$ 0	$ (2,700,000)
Regulatory assets, amortization of prior service cost, pension and other postretirement benefit plans, net of tax				(300,000)	(300,000)	(600,000)
Regulatory assets, prior service cost (credit), pension and other postretirement benefit plans, net of tax				0	0	0
Regulatory assets, amortization of transition obligation, pension and other postretirement benefit plans, net of tax				0	0	(200,000)
Regulatory assets, total recognized in regulatory assets, pension and other postretirement benefit plans, net of tax				(20,100,000)	(19,100,000)	(33,400,000)
Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Adoption of new mortality tables in 2014, gain					26,000,000
Adoption of modified mortality tables in 2015, gain				21,500,000
Defined Benefit Plan, Benefit Obligation	823,000,000			855,400,000	919,500,000	823,000,000
Service cost				24,100,000	20,000,000	21,800,000
Interest cost				38,200,000	40,400,000	38,500,000
Defined Benefit Plan, Contributions by Plan Participants				0	0
Defined Benefit Plan, Actuarial Net (Gains) Losses				62,400,000	(100,100,000)
Defined Benefit Plan, Benefits Paid				(64,000,000)	(64,000,000)
Defined Benefit Plan, Curtailments				$ 0	$ 0	9,900,000
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate				4.68%	4.20%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase				3.00%	3.00%
Defined Benefit Plan, Fair Value of Plan Assets	$ 870,000,000			$ 781,700,000	$ 861,800,000	870,000,000
Defined Benefit Plan, Funded Status of Plan				(73,700,000)	(57,700,000)
Defined Benefit Pension Plan, Liabilities, Noncurrent				(73,700,000)	(57,700,000)
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax				10,400,000	8,100,000
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Prior Service Cost (Credit), before Tax				200,000	300,000
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax				10,600,000	8,400,000
pension and other postretirement benefit plans, regulated assets, net gains, before tax				219,400,000	222,100,000
Pension and other postretirement benefit plans, regulatory assets, net prior service costs (credit), before tax				5,900,000	9,600,000
Pension and other postretirement benefit plans, regulatory assets, before tax				225,300,000	231,700,000
Defined Benefit Plan, Shared Costs Deferred				20.3	17.8
Regulatory assets, pension and other postretirement benefit plans, net unamortized gain (loss) arising during the period, net of tax				$ 9,200,000	$ 101,300,000	(157,500,000)
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	5.07%	4.10%		4.20%	5.03%
Expected return on assets				$ (62,000,000)	$ (66,700,000)	(61,400,000)
Defined Benefit Plan, Amortization of Transition Obligations (Assets)				0	0	0
Defined Benefit Plan, Actual Return on Plan Assets				$ (16,100,000)	$ 55,800,000
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	3.00%	3.75%		3.00%	3.00%
Regulatory assets, amortization of actuarial losses, pension and other postretirement benefit plans, net of tax				$ (11,900,000)	$ (4,000,000)	(14,700,000)
Regulatory assets, amortization of prior service cost, pension and other postretirement benefit plans, net of tax				(3,700,000)	(3,200,000)	(5,200,000)
Regulatory assets, prior service cost (credit), pension and other postretirement benefit plans, net of tax				0	0	(8,900,000)
Regulatory assets, amortization of transition obligation, pension and other postretirement benefit plans, net of tax				0	0	0
Regulatory assets, total recognized in regulatory assets, pension and other postretirement benefit plans, net of tax				$ (6,400,000)	(94,100,000)	(186,300,000)
SCE&G
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Period for which Annual Base Earnings are Considered Under Average Pay Formula				3
Defined Benefit Plan, Accumulated Benefit Obligation				$ 0	0
Defined Benefit Plan Health Care Cost Trend Rate, Assumed				7.00%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate				5.00%
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation				$ 0	0
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation				0	0
Defined Benefit Plan, Fair Value of Plan Assets				$ 720,000,000	$ 784,000,000
Transfers of fair value amounts into or out of Levels 1, 2 or 3				no	no
Defined Contribution Plan, Cost Recognized				$ 21,800,000	$ 20,700,000	18,700,000
SCE&G | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Adoption of new mortality tables in 2014, gain					2,000,000
Adoption of modified mortality tables in 2015, gain				2,000,000
Defined Benefit Plan, Benefit Obligation	$ 181,700,000			191,700,000	204,100,000	181,700,000
Service cost				4,400,000	3,600,000	4,600,000
Interest cost				9,400,000	9,400,000	$ 8,700,000
Defined Benefit Plan, Contributions by Plan Participants				1,900,000	1,800,000
Defined Benefit Plan, Actuarial Net (Gains) Losses				15,700,000	(18,600,000)
Defined Benefit Plan, Benefits Paid				$ (10,300,000)	$ (9,600,000)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate				4.78%	4.30%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase				3.00%	3.00%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate				5.00%	5.00%	5.00%
Defined Benefit Plan, Fair Value of Plan Assets				$ 0	$ 0
Defined Benefit Plan, Funded Status of Plan				(191,700,000)	(204,100,000)
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities				(9,800,000)	(8,500,000)
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent				0	0
Other Postretirement Defined Benefit Plan, Liabilities, Noncurrent				(181,900,000)	(195,600,000)
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax				700,000	1,000,000
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				700,000	1,000,000
pension and other postretirement benefit plans, regulated assets, net gains, before tax				20,400,000	35,900,000
Pension and other postretirement benefit plans, regulatory assets, net prior service costs (credit), before tax				200,000	500,000
Pension and other postretirement benefit plans, regulatory assets, before tax				20,600,000	36,400,000
Defined Benefit Plan, Shared Costs Deferred				13.8	15.1
Regulatory assets, pension and other postretirement benefit plans, net unamortized gain (loss) arising during the period, net of tax				$ (14,000,000)	$ 15,800,000	$ (24,400,000)
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate				4.30%	5.19%	4.19%
Defined Benefit Plan, Amounts Funded to Parent				$ (2,100,000)	$ (1,400,000)
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase				3.00%	3.75%	3.75%
Regulatory assets, amortization of actuarial losses, pension and other postretirement benefit plans, net of tax				$ (1,500,000)	$ 0	$ (2,200,000)
Regulatory assets, amortization of prior service cost, pension and other postretirement benefit plans, net of tax				(300,000)	(200,000)	(500,000)
Regulatory assets, prior service cost (credit), pension and other postretirement benefit plans, net of tax				0	0	0
Regulatory assets, amortization of transition obligation, pension and other postretirement benefit plans, net of tax				0	0	(100,000)
Regulatory assets, total recognized in regulatory assets, pension and other postretirement benefit plans, net of tax				(15,800,000)	(15,600,000)	(27,200,000)
SCE&G | Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Adoption of new mortality tables in 2014, gain					22,000,000
Adoption of modified mortality tables in 2015, gain				18,200,000
Defined Benefit Plan, Benefit Obligation	695,700,000			724,000,000	773,700,000	695,700,000
Service cost				19,300,000	16,000,000	17,600,000
Interest cost				32,200,000	34,100,000	32,600,000
Defined Benefit Plan, Contributions by Plan Participants				0	0
Defined Benefit Plan, Actuarial Net (Gains) Losses				47,000,000	(82,700,000)
Defined Benefit Plan, Benefits Paid				(54,200,000)	(54,800,000)
Defined Benefit Plan, Curtailments				$ 0	$ 0	8,400,000
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate				4.68%	4.20%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase				3.00%	3.00%
Defined Benefit Plan, Fair Value of Plan Assets	$ 792,100,000			$ 720,100,000	$ 783,600,000	792,100,000
Defined Benefit Plan, Funded Status of Plan				(3,900,000)	9,900,000
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent				0	9,900,000
Defined Benefit Pension Plan, Liabilities, Noncurrent					0
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax				2,000,000	1,900,000
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Prior Service Cost (Credit), before Tax				0	100,000
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax				2,000,000	2,000,000
pension and other postretirement benefit plans, regulated assets, net gains, before tax				193,700,000	191,900,000
Pension and other postretirement benefit plans, regulatory assets, net prior service costs (credit), before tax				5,200,000	8,300,000
Pension and other postretirement benefit plans, regulatory assets, before tax				198,900,000	200,200,000
Defined Benefit Plan, Shared Costs Deferred				20.3	17.8
Regulatory assets, pension and other postretirement benefit plans, net unamortized gain (loss) arising during the period, net of tax				$ 12,200,000	$ 87,700,000	(137,100,000)
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	5.07%	4.10%		4.20%	5.03%
Defined Benefit Plan, Amounts Funded to Parent				$ 0	$ 0
Expected return on assets				(52,200,000)	(56,300,000)	(51,900,000)
Defined Benefit Plan, Actual Return on Plan Assets				$ (9,300,000)	$ 46,300,000
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	3.00%	3.75%		3.00%	3.00%
Regulatory assets, amortization of actuarial losses, pension and other postretirement benefit plans, net of tax				$ (10,400,000)	$ (3,500,000)	(12,700,000)
Regulatory assets, amortization of prior service cost, pension and other postretirement benefit plans, net of tax				(3,100,000)	(2,800,000)	(4,500,000)
Regulatory assets, prior service cost (credit), pension and other postretirement benefit plans, net of tax				0	0	(7,700,000)
Regulatory assets, amortization of transition obligation, pension and other postretirement benefit plans, net of tax				0	0	0
Regulatory assets, total recognized in regulatory assets, pension and other postretirement benefit plans, net of tax				(1,300,000)	$ (81,400,000)	(162,000,000)
Pension Costs [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority	$ 63,000,000			14,000,000		63,000,000
Pension Costs [Member] | SCE&G
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority	$ 63,000,000			$ 14,000,000		$ 63,000,000
Regulatory assets, expected recovery period (in years)				12 years		14 years
Scenario, Forecast [Member] | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, future amortization of gain or loss from regulatory assets			$ 300,000
Defined benefit plan, future amortization of prior service cost (credit) from regulatory assets			300,000
Defined benefit plan, amount to be amortized from regulatory assets next year			600,000
Scenario, Forecast [Member] | Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, future amortization of gain or loss from regulatory assets			12,700,000
Defined benefit plan, future amortization of prior service cost (credit) from regulatory assets			3,400,000
Defined benefit plan, amount to be amortized from regulatory assets next year			$ 16,100,000
Scenario, Forecast [Member] | SCE&G
Defined Benefit Plan Disclosure [Line Items]
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 | Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, future amortization of gain or loss from regulatory assets			$ 300,000
Defined benefit plan, future amortization of prior service cost (credit) from regulatory assets			200,000
Defined benefit plan, amount to be amortized from regulatory assets next year			500,000
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			11,200,000
Defined benefit plan, future amortization of prior service cost (credit) from regulatory assets			3,000,000
Defined benefit plan, amount to be amortized from regulatory assets next year			$ 14,200,000

EMPLOYEE BENEFIT PLANS EMPLOYEE

EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Details 2)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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%	34.00%
Defined Benefit Plan, Target Plan Asset Allocation, Hedge Funds		11.00%	9.00%
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%	34.00%
Defined Benefit Plan, Target Plan Asset Allocation, Hedge Funds		11.00%	9.00%
Scenario, Forecast [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation, Equity Securities	58.00%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets	7.50%
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, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets	7.50%
Defined Benefit Plan, Target Plan Asset Allocations	33.00%
Defined Benefit Plan, Target Plan Asset Allocation, Hedge Funds	9.00%

EMPLOYEE BENEFIT PLANS EMPLOY59

EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 782	$ 862
Transfers of fair value amounts into or out of Levels 1, 2 or 3	no	no
Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 538	$ 622
Short-term Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	14	20
Agency Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	22	6
Corporate Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	78	86
Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	14	15
Limited Partner [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	33	32
Hedge Funds, Multi-strategy [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	83	81
Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	699	781
Fair Value, Inputs, Level 2 [Member] | Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	538	622
Fair Value, Inputs, Level 2 [Member] | Short-term Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	14
Fair Value, Inputs, Level 2 [Member] | Agency Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	22
Fair Value, Inputs, Level 2 [Member] | Corporate Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	78
Fair Value, Inputs, Level 2 [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	14
Fair Value, Inputs, Level 2 [Member] | Limited Partner [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	33	32
Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	83	81	$ 76
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unobservable Input, Unrealized Gains (Losses), Changes in Assets and Liabilities, Net	2	5
Defined Benefit Plan, Purchases, Sales, and Settlements	0	0
Fair Value, Inputs, Level 3 [Member] | Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Fair Value, Inputs, Level 3 [Member] | Short-term Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Fair Value, Inputs, Level 3 [Member] | Agency Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Fair Value, Inputs, Level 3 [Member] | Corporate Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Fair Value, Inputs, Level 3 [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Fair Value, Inputs, Level 3 [Member] | Limited Partner [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Fair Value, Inputs, Level 3 [Member] | Hedge Funds, Multi-strategy [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	83
SCE&G
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 720	$ 784
Transfers of fair value amounts into or out of Levels 1, 2 or 3	no	no
SCE&G | Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 496	$ 566
SCE&G | Short-term Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	12	18
SCE&G | Agency Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	20	6
SCE&G | Corporate Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	72	78
SCE&G | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	13	14
SCE&G | Limited Partner [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	30	29
SCE&G | Hedge Funds, Multi-strategy [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	77	73
SCE&G | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	643	711
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	496	566
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	12	18
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	20	6
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	72	78
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	14
SCE&G | Fair Value, Inputs, Level 2 [Member] | Limited Partner [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	30	29
SCE&G | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	77	73	$ 69
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unobservable Input, Unrealized Gains (Losses), Changes in Assets and Liabilities, Net	4	4
Defined Benefit Plan, Purchases, Sales, and Settlements	0	0
SCE&G | Fair Value, Inputs, Level 3 [Member] | Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
SCE&G | Fair Value, Inputs, Level 3 [Member] | Short-term Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
SCE&G | Fair Value, Inputs, Level 3 [Member] | Agency Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
SCE&G | Fair Value, Inputs, Level 3 [Member] | Corporate Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
SCE&G | Fair Value, Inputs, Level 3 [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
SCE&G | Fair Value, Inputs, Level 3 [Member] | Limited Partner [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
SCE&G | Fair Value, Inputs, Level 3 [Member] | Hedge Funds, Multi-strategy [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 77	$ 73

EMPLOYEE BENEFIT PLANS EMPLOY60

EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Details 4) $ in Millions	Dec. 31, 2015USD ($)
Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	$ 65.1
Defined Benefit Plan, Expected Future Benefit Payments, Year Two	63.2
Defined Benefit Plan, Expected Future Benefit Payments, Year Three	64.7
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	65.3
Defined Benefit Plan, Expected Future Benefit Payments, Year Five	65.8
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter	338.3
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	11.9
Defined Benefit Plan, Expected Future Benefit Payments, Year Two	12.7
Defined Benefit Plan, Expected Future Benefit Payments, Year Three	13.5
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	14.2
Defined Benefit Plan, Expected Future Benefit Payments, Year Five	14.9
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter	80.5
SCE&G | Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	65.1
Defined Benefit Plan, Expected Future Benefit Payments, Year Two	63.2
Defined Benefit Plan, Expected Future Benefit Payments, Year Three	64.7
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	65.3
Defined Benefit Plan, Expected Future Benefit Payments, Year Five	65.8
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter	338.3
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	9.8
Defined Benefit Plan, Expected Future Benefit Payments, Year Two	10.5
Defined Benefit Plan, Expected Future Benefit Payments, Year Three	11.1
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	11.7
Defined Benefit Plan, Expected Future Benefit Payments, Year Five	12.3
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter	$ 66.1

EMPLOYEE BENEFIT PLANS EMPLOY61

EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Details 5) - USD ($) $ in Millions	4 Months Ended	8 Months Ended	12 Months Ended
	Dec. 31, 2013	Aug. 31, 2013	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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	$ 1	$ 1
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax				$ 0	4	(8)
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				$ 26.2	25.8	$ 23.4
Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Pension Plan, Liabilities, Noncurrent				$ 73.7	$ 57.7
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	5.07%	4.10%		4.20%	5.03%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets				7.50%	8.00%	8.00%
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax				$ 2.7	$ 3.1	$ (5)
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax				(0.4)	(0.2)	(0.5)
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)	(0.2)	(0.2)
Other Comprehensive Income, Other Adjustments to Defined Benefit Plan, Net Prior Service Cost Recognized in Net Periodic Pension Cost, Net of Tax				0	0	(0.3)
Defined Benefit Plan, Amortization of Net Transition Asset (Obligation)				0	0	0
Defined Benefit Plan, Service Cost				24.1	20	21.8
Defined Benefit Plan, Interest Cost				38.2	40.4	38.5
Defined Benefit Plan, Expected Return on Plan Assets				(62)	(66.7)	(61.4)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)				4.1	4.1	6
Defined Benefit Plan, Amortization of Gains (Losses)				13.6	4.8	16.9
Defined Benefit Plan, Amortization of Transition Obligations (Assets)				0	0	0
Defined Benefit Plan, Curtailments				0	0	9.9
Defined Benefit Plan, Net Periodic Benefit Cost				18	2.6	31.7
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax				$ 2.2	$ 2.7	$ (6)
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	3.00%	3.75%		3.00%	3.00%
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate				4.30%	5.19%	4.19%
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax				$ (1.2)	$ 1.3	$ (1.8)
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax				(0.1)	0	(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	0
Other Comprehensive Income, Other Adjustments to Defined Benefit Plan, Net Prior Service Cost Recognized in Net Periodic Pension Cost, Net of Tax				0	0	0
Defined Benefit Plan, Amortization of Net Transition Asset (Obligation)				0	0	(0.1)
Defined Benefit Plan, Service Cost				5.3	4.6	5.9
Defined Benefit Plan, Interest Cost				11.4	12	11.1
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)				0.4	0.3	0.7
Defined Benefit Plan, Amortization of Gains (Losses)				2.1	0	3.3
Defined Benefit Plan, Amortization of Transition Obligations (Assets)				0	0	0.3
Defined Benefit Plan, Net Periodic Benefit Cost				19.2	16.9	21.3
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax				$ (1.4)	$ 1.3	$ (2.1)
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase				3.00%	3.75%	3.75%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year				7.00%	7.40%	7.80%
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	$ 1
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				$ 21.8	20.7	$ 18.7
SCE&G | Pension Plan, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Pension Plan, Liabilities, Noncurrent					$ 0
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	5.07%	4.10%		4.20%	5.03%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets				7.50%	8.00%	8.00%
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax				$ 0.2	$ 0.2	$ (0.8)
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				(0.1)	(0.1)	0
Defined Benefit Plan, Service Cost				19.3	16	17.6
Defined Benefit Plan, Interest Cost				32.2	34.1	32.6
Defined Benefit Plan, Expected Return on Plan Assets				(52.2)	(56.3)	(51.9)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)				3.4	3.5	5
Defined Benefit Plan, Amortization of Gains (Losses)				11.4	4	14.3
Defined Benefit Plan, Curtailments				0	0	8.4
Defined Benefit Plan, Net Periodic Benefit Cost				14.1	1.3	26
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax				$ 0	$ 0	$ (0.9)
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	3.00%	3.75%		3.00%	3.00%
SCE&G | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate				4.30%	5.19%	4.19%
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax				$ (0.3)	$ 0.4	$ (0.4)
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax				0	0	(0.1)
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Recognized in Net Periodic Pension Cost, Net of Tax				0	0	0
Defined Benefit Plan, Service Cost				4.4	3.6	4.6
Defined Benefit Plan, Interest Cost				9.4	9.4	8.7
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)				0.3	0.3	0.6
Defined Benefit Plan, Amortization of Gains (Losses)				1.7	0	2.6
Defined Benefit Plan, Net Periodic Benefit Cost				15.8	13.3	16.5
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax				$ (0.3)	$ 0.4	$ (0.5)
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase				3.00%	3.75%	3.75%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year				7.00%	7.40%	7.80%
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			7.50%
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)			0.2
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year			0.8
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
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
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			7.50%

SHARE-BASED COMPENSATION (Detai

SHARE-BASED COMPENSATION (Details)	Dec. 31, 2015shares
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. 29, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Liability Awards
Cash-Settled Liabilities		$ 20.8	$ 11.8	$ 12.2
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized		$ 20.4
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		$ 18	20.3	8.7
Capitalized Compensation Expense		$ 2.3	3.1	1.4
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		$ 6.3	1.9	3.2
Compensation Expenses Recognized Resulting From Fair Value Adjustments of Performance Awards		12.2	12.6	5.5
Capitalized Compensation Expense		$ 0.6	$ 0.6	$ 0.5
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	$ 18.4
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	$ 3.7
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, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Commitments and contingencies
Operating Leases, Future Minimum Payments Due, Next Twelve Months	$ 10,000,000
Asset Retirement Obligation, Liabilities Incurred	0	$ 3,000,000
Asset Retirement Obligation, Liabilities Settled	(16,000,000)	(6,000,000)
Environmental
Regulatory assets	1,937,000,000	1,823,000,000	$ 1,823,000,000
Operating Leases, Rent Expense	11.1	12.3	14.8
Nuclear Generation
Guarantor Obligations, Maximum Exposure, Undiscounted	1,800,000,000
Asset Retirement Obligation, Accretion Expense	25,000,000	26,000,000
Asset Retirement Obligation, Revision of Estimate	(52,000,000)	(36,000,000)
Asset Retirement Obligation	520,000,000	563,000,000	576,000,000
Operating Leases, Future Minimum Payments, Due in Two Years	7,000,000
Operating Leases, Future Minimum Payments, Due in Three Years	6,000,000
Operating Leases, Future Minimum Payments, Due in Four Years	6,000,000
Operating Leases, Future Minimum Payments, Due in Five Years	3,000,000
Operating Leases, Future Minimum Payments, Due Thereafter	27,000,000
Asset Retirement Obligation Other Conditional Obligations	344,000,000
Jointly Owned Nuclear Power Plant [Member]
Nuclear Insurance
Maximum liability assessment per reactor for each nuclear incident	127,300,000
SCE&G
Commitments and contingencies
Federal Limit on Public Liability Claims from Nuclear Incident Approximate	13,400,000,000
Operating Leases, Future Minimum Payments Due, Next Twelve Months	4,000,000
Asset Retirement Obligation, Liabilities Incurred	0	3,000,000
Asset Retirement Obligation, Liabilities Settled	(16,000,000)	(6,000,000)
Nuclear Insurance
scg_Maximum Insurance Coverage for each Nuclear Plant by ANI	375,000,000
Maximum liability assessment per reactor for each nuclear incident	84,800,000
Maximum yearly assessment per reactor	18,900,000
Maximum Insurance Coverage for Nuclear events	2,750,000,000
Maximum prosepective insurance premium per nuclear incident	43,500,000
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
Environmental
Environmental Remediation Expense	18,500,000
Deferred costs, net of costs previously recovered through rates and insurance settlements included in regulatory assets	$ 34,800,000
Number of MGP Sites Requiring Clean Up [Member]	4
Regulatory assets	$ 1,857,000,000	1,745,000,000	1,745,000,000
Operating Leases, Rent Expense	12.3	12.1	13.6
Nuclear Generation
Asset Retirement Obligation Nuclear Decommissioning	176,000,000
Asset Retirement Obligation, Accretion Expense	23,000,000	25,000,000
Asset Retirement Obligation, Revision of Estimate	(55,000,000)	(33,000,000)
Asset Retirement Obligation	488,000,000	536,000,000	$ 547,000,000
Operating Leases, Future Minimum Payments, Due in Two Years	2,000,000
Operating Leases, Future Minimum Payments, Due in Three Years	1,000,000
Operating Leases, Future Minimum Payments, Due in Four Years	1,000,000
Operating Leases, Future Minimum Payments, Due in Five Years	1,000,000
Operating Leases, Future Minimum Payments, Due Thereafter	17,000,000
Asset Retirement Obligation Other Conditional Obligations	312,000,000
Summer Station New Units and Transmission Assets [Member]
Nuclear Generation
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	3,600,000,000
Summer Station New Units [Domain]
Nuclear Generation
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	3,400,000,000	$ 2,700,000,000
jointly owned utility plant ownership, construction financing cost	3,200,000,000
SCE&G | SCE&G
Nuclear Insurance
Maximum yearly assessment per reactor	$ 12,600,000

COMMITMENTS AND CONTINGENCIES N

COMMITMENTS AND CONTINGENCIES Nuclear (Details)	12 Months Ended
	Dec. 31, 2015USD ($)	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2014USD ($)
Forecasted Incremental Capital Costs Associated With Schedule Delays, 2015 Petition	$ 539,000,000
EPC Contract Amendment, New Nuclear Construction Completion Bonus	151,000,000
Aggregate Nominal Coverage of Bond	100,000,000
Aggregate Nominal Coverage of Bond, SCE&G Share	55,000,000
EPC Contract Amendment, Fixed Price Option, Increase In Total New Nuclear Project Cost	$ 774,000,000
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
Capital costs, owners [Domain]
Forecasted incremental capital costs, 2015 petition	$ 245,000,000
Forecasted Total Capital Costs, 2015 Petition	5,200,000,000
Capital costs, Other [Domain] [Domain]
Forecasted incremental capital costs, 2015 petition	453,000,000
Forecasted Total Capital Costs, 2015 Petition	6,800,000,000
SCE&G
EPC Contract Amendment, Credit Applied To Target Component Of New Units Contract Price	27,000,000
EPC Contract Amendment, Increase In Fixed Component Of Contract Price	165,000,000
EPC Contract Amendment, Cap On Delay Oriented Liquidated Damages Per New Nuclear Unit	255,000,000
EPC Contract Amendment, Revised Construction Milestone Payment Schedule, Per Month	55,000,000
EPC Contract Amendment, Increase In Total New Nuclear Project Cost	286,000,000
Total New Nuclear Project Cost Approved By SCPSC In September 2015	7,000,000,000
EPC Contract Amendment, Fixed Price Option, Project Cost Including Fixed Option Price Increase	7,600,000,000
EPC Contract Amendment, Total New Nuclear Project Cost Including Amendment Increase	7,000,000,000
Aggregate Nominal Coverage of Bond	100,000,000
Aggregate Nominal Coverage of Bond, SCE&G Share	55,000,000
EPC Contract Amendment, Fixed Price Option, Price For New Nuclear Construction After June 2015	3,345,000,000
EPC Contract Amendment, Fixed Price Option, Cap On Delay Oriented Liquidated Damages Per New Nuclear Unit	186,000,000
EPC Contract Amendment, Fixed Price Option, New Nuclear Construction Completion Bonus	83,000,000
Summer Station New Units [Domain]
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	3,400,000,000				$ 2,700,000,000
jointly owned utility plant ownership, construction financing cost	3,200,000,000
EPC Contract Amendment, Credit Applied To Target Component Of New Units Contract Price	50,000,000
EPC Contract Amendment, Increase In Fixed Component Of Contract Price	300,000,000
EPC Contract Amendment, Cap On Delay Oriented Liquidated Damages Per New Nuclear Unit	463,000,000
EPC Contract Amendment, New Nuclear Construction Completion Bonus	275,000,000
EPC Contract Amendment, Revised Construction Milestone Payment Schedule, Per Month	100,000,000
EPC Contract Amendment, Fixed Price Option, Price For New Nuclear Construction After June 2015	6,082,000,000
EPC Contract Amendment, Fixed Price Option, Cap On Delay Oriented Liquidated Damages Per New Nuclear Unit	338,000,000
EPC Contract Amendment, Fixed Price Option, New Nuclear Construction Completion Bonus	150,000,000
Nuclear Production Tax Credits	1,400,000,000
Scenario, Forecast [Member] | SCE&G
Additional ownership in new units		2.00%	2.00%	1.00%
Minimum [Member] | SCE&G
Additional ownership in new units, dollars	750,000,000
Maximum [Member] | SCE&G
Additional ownership in new units, dollars	$ 850,000,000

AFFILIATED TRANSACTIONS - SCEG

AFFILIATED TRANSACTIONS - SCEG (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Affiliated Transaction [Line Items]
Proceeds from Equity Method Investment, Dividends or Distributions	$ 4	$ 7.8	$ 10.4
Equity Method Investments	4.1	5.7	5.2
Related Party Transaction, Expenses from Transactions with Related Party	300	292.2	285.6
Canadys Refined Coal LLC [Member]
Affiliated Transaction [Line Items]
Related Party Transaction Purchases from Related Party	233.2	260.3	134.2
Sales to Affiliate	$ 232	259	133.6
Equity Method Investment, Ownership Percentage	40.00%
Related Party Tax Expense, Due from Affiliates, Current	$ 12.8	27.8
Related Party Tax Expense, Due to Affiliates, Current	12.9	27.9
SCE&G
Affiliated Transaction [Line Items]
Due to Affiliate, Current	113	180
Due from Affiliate, Current	22	109
Related Party Transaction, Due from (to) Related Party, Current	9	80
Accounts Payable, Related Parties, Current	57	47.3
CGT [Member]
Affiliated Transaction [Line Items]
Related Party Transaction Purchases from Related Party	3.4	30	33.3
Due to Affiliate, Current		3.3
Due from Affiliate, Current		1.2
Retail Gas and Energy Marketing Segment [Member]
Affiliated Transaction [Line Items]
Due to Affiliate, Current	7.5	12.6
Cost of Natural Gas Purchases	$ 128.5	$ 195.7	$ 166.9

SEGMENT OF BUSINESS INFORMATI67

SEGMENT OF BUSINESS INFORMATION (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Total	$ 17,146				$ 16,818				$ 17,146	$ 16,818	$ 15,127
Additions to Other Assets, Amount									1,153	1,092	1,106
Deferred Tax Assets, Gross	0				0				0	0	0
Electric Domestic Regulated Revenue									2,551	2,622	2,423
Regulated and Unregulated Operating Revenue	956	$ 1,068	$ 967	$ 1,389	1,214	$ 1,121	$ 1,026	$ 1,590	4,380	4,951	4,495
Intersegment Revenue									0	0	0
Operating Income	214	292	216	586	234	269	154	350	1,308	1,007	910
Interest Expense									318	312	297
Depreciation, Depletion and Amortization									358	384	378
Income Tax Expense (Benefit)									393	248	223
Income Available to Common Shareholders	98	149	99	400	105	144	96	193	746	538	471
Regulated Operating Revenue, Gas									811	1,028	955
Electric Operations
Segment Reporting Information [Line Items]
Total	10,883				10,182				10,883	10,182	9,488
Additions to Other Assets, Amount									1,087	936	907
Deferred Tax Assets, Gross	(5)				(11)				(5)	(11)	(10)
Intersegment Revenue									6	7	6
Operating Income									876	768	679
Interest Expense									17	19	19
Depreciation, Depletion and Amortization									277	300	297
Income Tax Expense (Benefit)									9	7	6
Gas Distribution
Segment Reporting Information [Line Items]
Total	2,606				2,487				2,606	2,487	2,340
Additions to Other Assets, Amount									203	200	140
Deferred Tax Assets, Gross	(29)				(29)				(29)	(29)	(27)
Regulated and Unregulated Operating Revenue									810	1,012	942
Intersegment Revenue									2	2	1
Operating Income									152	159	153
Interest Expense									23	22	22
Depreciation, Depletion and Amortization									77	72	70
Income Tax Expense (Benefit)									32	33	33
Retail Gas and Energy Marketing Segment [Member]
Segment Reporting Information [Line Items]
Total	95				150				95	150	133
Additions to Other Assets, Amount									2	2	1
Deferred Tax Assets, Gross	(6)				(9)				(6)	(9)	(2)
Regulated and Unregulated Operating Revenue									569	786	652
Intersegment Revenue									128	196	167
Income Tax Expense (Benefit)									6	3	4
Income Available to Common Shareholders									9	5	6
All Other [member]
Segment Reporting Information [Line Items]
Total	998				1,474				998	1,474	1,378
Additions to Other Assets, Amount									15	52	31
Deferred Tax Assets, Gross	0				(15)				0	(15)	(14)
Regulated and Unregulated Operating Revenue									5	37	40
Intersegment Revenue									413	437	416
Operating Income									236	27	27
Interest Expense									1	5	4
Depreciation, Depletion and Amortization									16	24	26
Income Tax Expense (Benefit)									1	12	14
Income Available to Common Shareholders									185	(6)	(2)
Retail Gas Marketing
Segment Reporting Information [Line Items]
Total	106				140				106	140	172
Additions to Other Assets, Amount									0	0	0
Deferred Tax Assets, Gross	(9)				(11)				(9)	(11)	(8)
Regulated and Unregulated Operating Revenue									449	515	465
Intersegment Revenue									0	0	0
Interest Expense									1	1	1
Depreciation, Depletion and Amortization									2	2	3
Income Tax Expense (Benefit)									12	16	15
Income Available to Common Shareholders									19	26	24
Adjustments/Eliminations
Segment Reporting Information [Line Items]
Total	2,458				2,385				2,458	2,385	1,616
Additions to Other Assets, Amount									(154)	(98)	27
Deferred Tax Assets, Gross	49				75				49	75	61
Regulated and Unregulated Operating Revenue									(4)	(21)	(27)
Intersegment Revenue									(549)	(642)	(590)
Operating Income									44	53	51
Interest Expense									276	265	251
Depreciation, Depletion and Amortization									(14)	(14)	(18)
Income Tax Expense (Benefit)									333	177	151
Income Available to Common Shareholders									533	513	443
SCE&G
Segment Reporting Information [Line Items]
Total	14,765				14,078				14,765	14,078	12,673
Additions to Other Assets, Amount									1,008	934	1,003
Deferred Tax Assets, Gross	0				0				0	0	0
Electric Domestic Regulated Revenue									2,557	2,629	2,431
Regulated Operating Revenue	643	806	709	772	722	812	698	859	2,930	3,091	2,845
Operating Income	172	$ 307	$ 218	$ 237	174	$ 272	$ 145	$ 239	934	830	737
Interest Expense									248	228	217
Depreciation, Depletion and Amortization									294	315	313
Income Tax Expense (Benefit)									231	218	189
Regulated Operating Revenue, Gas									373	462	414
SCE&G | Electric Operations
Segment Reporting Information [Line Items]
Total	10,883								10,883		9,488
Additions to Other Assets, Amount									1,087		907
Deferred Tax Assets, Gross	(5)								(5)		(10)
Operating Income									876		679
Interest Expense									17	19	19
Depreciation, Depletion and Amortization									277	300	294
SCE&G | Gas Distribution
Segment Reporting Information [Line Items]
Total	757				721				757	721	686
Additions to Other Assets, Amount									57	55	45
Regulated and Unregulated Operating Revenue									373	462	414
Operating Income									58	62	58
Interest Expense									0	0	0
Depreciation, Depletion and Amortization									28	27	26
SCE&G | Adjustments/Eliminations
Segment Reporting Information [Line Items]
Total	3,125				3,175				3,125	3,175	2,499
Additions to Other Assets, Amount									(136)	(57)	51
Deferred Tax Assets, Gross	$ (5)				$ (11)				(5)	(11)	(10)
Operating Income											0
Interest Expense									231	209	198
Depreciation, Depletion and Amortization									(11)	(12)	(7)
External revenue [Member] | SCE&G
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue									$ 2,557	$ 2,629	$ 2,431

DISPOSITIONS (Details)

DISPOSITIONS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Proceeds from sale of CGT and SCI net of transaction costs	$ 647
Public Utilities, Property, Plant and Equipment, Net	13,145	$ 12,232
Nonutility Property and Investments, Net	466	472
Assets, Current	1,378	2,145
Regulated Entity, Other Assets, Noncurrent	2,157	1,969
Disposal group current assets held for sale	0	341
Liabilities, Current	1,952	2,468
Liabilities, Noncurrent	3,869	3,866
Liabilities held for sale	0	52
Estimated pre-tax gain on sale of CGT and SCI	$ 341
Liabilities, Held for Sale [Member] | CGT [Member]
Liabilities, Current		3.5
Liabilities, Noncurrent		42.9
Liabilities held for sale		46.4
Liabilities, Held for Sale [Member] | SCANA Communications [Member]
Liabilities, Current		2.2
Liabilities, Noncurrent		3.1
Liabilities held for sale		5.3
Liabilities, Held for Sale [Member] | Held for Sale, CGT and SCI [Member]
Liabilities, Current		5.7
Liabilities, Noncurrent		46
Liabilities held for sale		51.7
Assets Held-for-sale [Member] | CGT [Member]
Public Utilities, Property, Plant and Equipment, Net		288.4
Nonutility Property and Investments, Net		0.6
Assets, Current		6.5
Regulated Entity, Other Assets, Noncurrent		0.9
Disposal group current assets held for sale		296.4
Assets Held-for-sale [Member] | SCANA Communications [Member]
Public Utilities, Property, Plant and Equipment, Net		0
Nonutility Property and Investments, Net		40.1
Assets, Current		3.9
Regulated Entity, Other Assets, Noncurrent		0.2
Disposal group current assets held for sale		44.2
Assets Held-for-sale [Member] | Held for Sale, CGT and SCI [Member]
Public Utilities, Property, Plant and Equipment, Net		288.4
Nonutility Property and Investments, Net		40.7
Assets, Current		10.4
Regulated Entity, Other Assets, Noncurrent		1.1
Disposal group current assets held for sale		$ 340.6

QUARTERLY FINANCIAL INFORMATI69

QUARTERLY FINANCIAL INFORMATION (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Regulated and Unregulated Operating Revenue	$ 956	$ 1,068	$ 967	$ 1,389	$ 1,214	$ 1,121	$ 1,026	$ 1,590	$ 4,380	$ 4,951	$ 4,495
Operating Income (Loss)	214	292	216	586	234	269	154	350	1,308	1,007	910
Income Available to Common Shareholders	$ 98	$ 149	$ 99	$ 400	$ 105	$ 144	$ 96	$ 193	$ 746	$ 538	471
Earnings Per Share, Basic and Diluted	$ 0.69	$ 1.04	$ 0.69	$ 2.80	$ 0.73	$ 1.01	$ 0.68	$ 1.37	$ 5.22	$ 3.79
SCE&G
Regulated Operating Revenue	$ 643	$ 806	$ 709	$ 772	$ 722	$ 812	$ 698	$ 859	$ 2,930	$ 3,091	2,845
Operating Income (Loss)	172	307	218	237	174	272	145	239	934	830	737
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	76	167	111	126	76	157	99	126	480	458	391
Net Income (Loss) Attributable to Parent	$ 73	$ 164	$ 107	$ 122	$ 73	$ 154	$ 96	$ 123	$ 466	$ 446	$ 380

Schedule II (Details)

Schedule II (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Allowance for Doubtful Accounts [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Valuation Allowances and Reserves, Balance	$ 5	$ 7	$ 6	$ 7
Valuation Allowances and Reserves, Charged to Cost and Expense	12	16	13
Valuation Allowances and Reserves, Charged to Other Accounts	0	0	0
Valuation Allowances and Reserves, Deductions	14	15	14
General Liability [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Valuation Allowances and Reserves, Balance	6	5	6	6
Valuation Allowances and Reserves, Charged to Cost and Expense	11	7	4
Valuation Allowances and Reserves, Charged to Other Accounts	0	0	0
Valuation Allowances and Reserves, Deductions	10	8	4
SCE&G | Allowance for Doubtful Accounts [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Valuation Allowances and Reserves, Balance	3	4	3	3
Valuation Allowances and Reserves, Charged to Cost and Expense	6	8	7
Valuation Allowances and Reserves, Charged to Other Accounts	0	0	0
Valuation Allowances and Reserves, Deductions	7	7	7
SCE&G | General Liability [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Valuation Allowances and Reserves, Balance	5	3	5	$ 5
Valuation Allowances and Reserves, Charged to Cost and Expense	11	1	3
Valuation Allowances and Reserves, Charged to Other Accounts	0	0	0
Valuation Allowances and Reserves, Deductions	$ 9	$ 3	$ 3