Scana 10-Q 6 Nov 15 2015 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information Document	9 Months Ended
	Sep. 30, 2015shares
Entity Information [Line Items]
Entity Registrant Name	SCANA Corporation
Entity Central Index Key	754,737
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding	142,916,917
SCEG
Entity Information [Line Items]
Entity Registrant Name	SOUTH CAROLINA ELECTRIC & GAS CO
Entity Central Index Key	91,882
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding	40,296,147

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Assets
Utility Plant In Service	$ 12,692	$ 12,289
Accumulated Depreciation and Amortization	(4,268)	(4,088)
Construction Work in Progress	3,790	3,323
Plant to be Retired, Net	0	169
Nuclear Fuel, Net of Accumulated Amortization	305	329
Goodwill, Net of Writedown of $230	210	210
Utility Plant, Net	12,729	12,232
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	281	284
Assets held in trust, net-nuclear decommissioning	113	113
Other investments	73	75
Nonutility Property and Investments, Net	467	472
Current Assets:
Cash and cash equivalents	54	137
Receivables, net of allowance for uncollectible accounts	618	838
Inventories (at average cost):
Fuel	164	222
Materials and supplies	147	139
Prepaid Expense	132	320
Other current assets	106	148
Assets held for sale	0	341
Total Current Assets	1,221	2,145
Deferred Debits and Other Assets:
Regulatory Assets, Noncurrent	1,884	1,823
Other	205	180
Total Deferred Debits and Other Assets	2,089	2,003
Total	16,506	16,852
Capitalization and Liabilities
Common Stock, Value, Outstanding	2,391	2,378
Retained Earnings, Unappropriated	3,098	2,684
Accumulated Other Comprehensive Income (Loss), Net of Tax	(70)	(75)
Common equity	5,419	4,987
Long-term Debt, Excluding Current Maturities	6,018	5,531
Total Capitalization	11,437	10,518
Current Liabilities:
Short-term borrowings	264	918
Current portion of long-term debt	16	166
Accounts payable	312	520
Customer deposits and customer prepayments	110	98
Taxes accrued	183	182
Interest accrued	85	83
Dividends declared	76	73
Liabilities held for sale		52
Derivative financial instruments	125	233
Other	123	208
Total Current Liabilities	1,294	2,533
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,839	1,866
Deferred investment tax credits	26	28
Asset retirement obligations	489	563
Pension and other postretirement benefits	320	315
Regulatory Liabilities	859	814
Other	242	215
Total Deferred Credits and Other Liabilities	3,775	3,801
Total	16,506	16,852
SCEG
Assets
Utility Plant In Service	11,007	10,650
Accumulated Depreciation and Amortization	(3,830)	(3,667)
Construction Work in Progress	3,734	3,302
Plant to be Retired, Net	0	169
Nuclear Fuel, Net of Accumulated Amortization	305	329
Utility Plant, Net	11,216	10,783
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	67	67
Assets held in trust, net-nuclear decommissioning	113	113
Other investments	2	2
Nonutility Property and Investments, Net	182	182
Current Assets:
Cash and cash equivalents	30	100
Receivables, net of allowance for uncollectible accounts	462	524
Due from Affiliate, Current	22	109
Inventories (at average cost):
Fuel	102	131
Materials and supplies	136	129
Prepaid Expense	100	154
Other current assets	80	99
Total Current Assets	932	1,246
Deferred Debits and Other Assets:
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent	9	10
Regulatory Assets, Noncurrent	1,808	1,745
Other	165	141
Total Deferred Debits and Other Assets	1,982	1,896
Total	14,312	14,107
Capitalization and Liabilities
Common Stock, Value, Outstanding	2,756	2,560
Retained Earnings, Unappropriated	2,266	2,077
Accumulated Other Comprehensive Income (Loss), Net of Tax	(3)	(3)
Common equity	5,019	4,634
Stockholders' Equity Attributable to Noncontrolling Interest	129	123
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	5,148	4,757
Long-term Debt, Excluding Current Maturities	4,790	4,299
Total Capitalization	9,938	9,056
Current Liabilities:
Short-term borrowings	234	709
Current portion of long-term debt	10	10
Accounts payable	184	294
Due to Affiliate, Current	125	180
Customer deposits and customer prepayments	69	61
Taxes accrued	279	170
Interest accrued	66	64
Dividends declared	71	74
Derivative financial instruments	108	208
Other	76	99
Total Current Liabilities	1,222	1,869
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,682	1,696
Deferred investment tax credits	26	28
Asset retirement obligations	460	536
Pension and other postretirement benefits	198	195
Regulatory Liabilities	641	610
Other	145	117
Total Deferred Credits and Other Liabilities	3,152	3,182
Total	$ 14,312	$ 14,107

CONDENSED CONSOLIDATED BALANCE3

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) shares in Millions, $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Common Stock, Shares, Outstanding	142.9	142.7
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	$ 122	$ 122
Public Utilities, Property, Plant and Equipment, Net	12,729	12,232
Allowance for Doubtful Accounts Receivable, Current	5	7
Write-down, Goodwill	230	230
Assets, Current	1,221	2,145
Regulated Entity, Other Assets, Noncurrent	$ 2,089	$ 2,003
SCEG
Common Stock, Shares, Outstanding	40.3	40.3
Public Utilities, Property, Plant and Equipment, Net	$ 11,216	$ 10,783
Allowance for Doubtful Accounts Receivable, Current	4	4
Assets, Current	932	1,246
Regulated Entity, Other Assets, Noncurrent	1,982	1,896
SCEG | Variable Interest Entity, Primary Beneficiary [Member]
Public Utilities, Property, Plant and Equipment, Net	694	675
Assets, Current	100	158
Regulated Entity, Other Assets, Noncurrent	$ 52	$ 50

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Operating Revenues:
Electric Domestic Regulated Revenue	$ 742	$ 739	$ 2,008	$ 2,027
Regulated Operating Revenue, Gas	112	132	610	740
Gas-nonregulated	214	250	805	969
Regulated and Unregulated Operating Revenue	1,068	1,121	3,423	3,736
Operating Expenses [Abstract]
Fuel used in electric generation	187	212	525	636
Purchased power	14	13	38	54
Gas purchased for resale	260	304	1,030	1,291
Other operation and maintenance	182	169	527	523
Depreciation and amortization	75	96	267	286
Other taxes	58	58	176	174
Total Operating Expenses	776	852	2,563	2,964
Gain (Loss) on Disposition of Regulated Business Net of Transaction Costs	0	0	235	0
Operating Income	292	269	1,095	772
Other Income (Expense):
Other income	19	18	56	103
Other expense	(16)	(12)	(44)	(39)
Gain (Loss) On Disposition Of Unregulated Business Net Of Transaction Costs	0	0	107	0
Interest Expense	(81)	(79)	(236)	(231)
Allowance for equity funds used during construction	8	11	20	26
Total Other Expense	(70)	(62)	(97)	(141)
Income Before Income Tax Expense	222	207	998	631
Income Tax Expense	73	63	350	198
Net Income	$ 149	$ 144	$ 648	$ 433
Per Common Share Data
Basic Earnings Per Share of Common Stock (in dollars per share)	$ 1.04	$ 1.01	$ 4.53	$ 3.06
Weighted Average Number of Shares Outstanding, Basic and Diluted	142.9	142.1	142.9	141.6
Weighted Average Common Shares Outstanding (millions)
Common Stock, Dividends, Per Share, Declared	$ 0.545	$ 0.525	$ 1.635	$ 1.575
SCEG
Operating Revenues:
Electric Domestic Regulated Revenue	$ 743	$ 740	$ 2,013	$ 2,032
Regulated Operating Revenue, Gas	63	72	275	337
Regulated Operating Revenue	806	812	2,288	2,369
Operating Expenses [Abstract]
Fuel used in electric generation	187	213	525	640
Purchased power	14	13	38	54
Gas purchased for resale	37	46	151	210
Other operation and maintenance	148	136	428	415
Depreciation and amortization	59	79	220	236
Other taxes	54	53	163	158
Total Operating Expenses	499	540	1,525	1,713
Operating Income	307	272	763	656
Other Income (Expense):
Other income	6	9	24	71
Other expense	(7)	(7)	(21)	(19)
Interest Expense	(63)	(57)	(183)	(169)
Allowance for equity funds used during construction	8	10	18	22
Total Other Expense	(56)	(45)	(162)	(95)
Income Before Income Tax Expense	251	227	601	561
Income Tax Expense	84	70	196	178
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	167	157	405	383
Net Income (Loss) Attributable to Noncontrolling Interest	(3)	(3)	(11)	(9)
Earnings Available to Common Shareholder	164	154	394	374
Dividends Common Stock Declared	$ 71	$ 69	$ 211	$ 197

CONDENSED CONSOLIDATED STATEME5

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Allowance for Funds Used During Construction, Capitalized Interest	$ 5	$ 5	$ 12	$ 13
SCEG
Allowance for Funds Used During Construction, Capitalized Interest	$ 4	$ 5	$ 11	$ 11

CONDENSED CONSOLIDATED STATEME6

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Net Income (Loss) Attributable to Parent [Abstract]
Net Income (Loss) Available to Common Stockholders, Basic	$ 149	$ 144	$ 648	$ 433
Other Comprehensive Income (Loss)
Unrealized gains (losses) on cash flow hedging activities arising during period	(7)	(2)	8	3
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	(4)	0	8	(2)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, before Reclassification Adjustments, Net of Tax	(1)		3	1
Other Comprehensive Income (Loss)	(3)	1	5	(1)
Comprehensive income available to common shareholder	146	145	653	432
SCEG
Other Comprehensive Income (Loss)
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	167	157	405	383
Comprehensive income available to common shareholder			405	383
Genco
Other Comprehensive Income (Loss)
Less comprehensive income attributable to noncontrolling interest	3	3	11	9
SCE&G (including Fuel Company)
Net Income (Loss) Attributable to Parent [Abstract]
Net Income (Loss) Available to Common Stockholders, Basic			394	374
Other Comprehensive Income (Loss)
Comprehensive income available to common shareholder	164	154	394	374
Commodity Contract
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	1	0	10	(4)
Interest Rate Contract
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	2	2	6	5
Cash Flow Hedging [Member] | Interest Expense [Member] | Interest Rate Contract
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ (2)	$ (2)	$ (6)	$ (5)

CONDENSED CONSOLIDATED STATEME7

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Tax	$ 0	$ 0	$ (2)	$ 0
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	(4)	(1)	(5)	(2)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax	1	1	3	3
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income, Tax	0	0	6	(3)
Commodity Contract
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 1	$ 0	$ 10	$ (4)

CONDENSED CONSOLIDATED STATEME8

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Cash Flows From Operating Activities:
Net Income (Loss) Available to Common Stockholders, Basic	$ 648	$ 433
Adjustments to reconcile net income to net cash provided from operating activities:
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal	(355)
Loss from Equity Method Investments, Net of Dividends or Distributions	2	2
Deferred Income Tax Expense (Benefit)	(98)	63
Depreciation and amortization	276	298
Amortization of nuclear fuel	41	31
Allowance for equity funds used during construction	(20)	(26)
Carrying cost recovery	(9)	(7)
Cash provided (used) by changes in certain assets and liabilities:
Receivables	192	111
Inventories	2	(34)
Prepaid Expense	196	(99)
Other Regulatory Assets	92	(171)
Regulatory liabilities	9	(133)
Accounts payable	(85)	(18)
Taxes accrued	2	(69)
Increase (Decrease) in Pension and Postretirement Obligations	(1)	(13)
Increase (Decrease) in Derivative Assets and Liabilities	(108)	105
Changes in other assets	73	25
Changes in other liabilities	(50)	60
Net Cash Provided From Operating Activities	807	558
Cash Flows From Investing Activities:
Property additions and construction expenditures	(851)	(778)
Proceeds from Sale of Property, Plant, and Equipment	647
Proceeds from investments (including derivative collateral posted)	872	204
Purchase of investments (including derivative collateral posted)	(872)	(247)
Payments for Hedge, Investing Activities	(152)	(34)
Proceeds from Hedge, Investing Activities	10	0
Net Cash Used in Investing Activities	(346)	(855)
Cash Flows From Financing Activities:
Proceeds from Issuance of Common Stock	14	75
Proceeds from Issuance of Long-term Debt	491	294
Repayments of Long-term Debt	(164)	(17)
Dividends	(231)	(220)
Short-term borrowings, net	(654)	111
Net Cash Provided From Financing Activities	(544)	243
Net (Decrease) Increase in Cash and Cash Equivalents	(83)	(54)
Cash and Cash Equivalents, January 1	137	136
Cash and Cash Equivalents, September 30	54
Supplemental Cash Flow Information:
Cash paid for-Interest (net of capitalized interest )	224	225
Cash paid for-Income taxes	184	246
Noncash Investing and Financing Activities:
Accrued construction expenditures	85	108
Capital Lease Obligations Incurred	5	4
SCEG
Cash Flows From Operating Activities:
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	405	383
Adjustments to reconcile net income to net cash provided from operating activities:
Loss from Equity Method Investments	3	4
Deferred Income Tax Expense (Benefit)	(14)	76
Depreciation and amortization	221	236
Amortization of nuclear fuel	41	31
Allowance for equity funds used during construction	(18)	(22)
Carrying cost recovery	(9)	(7)
Cash provided (used) by changes in certain assets and liabilities:
Receivables	46	(34)
Inventories	(15)	(36)
Prepaid Expense	63	(24)
Other Regulatory Assets	90	(170)
Regulatory liabilities	6	(130)
Accounts payable	(21)	11
Taxes accrued	109	(70)
Increase (Decrease) in Pension and Postretirement Obligations	(2)	(12)
Increase (Decrease) in Derivative Assets and Liabilities	(100)	103
Changes in other assets	58	27
Changes in other liabilities	(61)	58
Net Cash Provided From Operating Activities	802	424
Cash Flows From Investing Activities:
Property additions and construction expenditures	(748)	(678)
Proceeds from investments (including derivative collateral posted)	768	163
Purchase of investments (including derivative collateral posted)	(776)	(202)
Payments for Hedge, Investing Activities	(152)	(34)
Proceeds from Hedge, Investing Activities	10
Investment In Affiliate	80
Net Cash Used in Investing Activities	(818)	(751)
Cash Flows From Financing Activities:
Proceeds from Issuance of Long-term Debt	491	294
Repayments of Long-term Debt	(10)	(12)
Dividends	(214)	(190)
Contributions from parent	200	85
Return of Capital to Parent	(4)	(3)
Short-term borrowings-affiliate,net	(42)	(7)
Short-term borrowings, net	(475)	110
Net Cash Provided From Financing Activities	(54)	277
Net (Decrease) Increase in Cash and Cash Equivalents	(70)	(50)
Cash and Cash Equivalents, January 1	100	92
Cash and Cash Equivalents, September 30	30	42
Supplemental Cash Flow Information:
Cash paid for-Interest (net of capitalized interest )	169	162
Income Taxes Paid	89
Cash paid for-Income taxes		143
Proceeds from Income Tax Refunds	(84)
Noncash Investing and Financing Activities:
Accrued construction expenditures	76	94
Capital Lease Obligations Incurred	$ 5	$ 4

CONDENSED CONSOLIDATED STATEME9

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Interest Paid, Capitalized	$ 12	$ 13
SCEG
Interest Paid, Capitalized	$ 11	$ 11

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	9 Months Ended
	Sep. 30, 2015
Significant Accounting Policies
Significant Accounting Policies [Text Block]	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles 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. 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. In the third quarter of 2015, in connection with the adoption of a customary depreciation study and related analysis, SCE&G determined that these three units would not likely be retired by 2020 (see Note 2), 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 September 30, 2015. 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 50% and 48% of PSNC Energy’s natural gas inventory at September 30, 2015 and December 31, 2014, respectively, with a carrying value of $19.1 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 of which 75% are credited to rate payers. No fees are received under supply service agreements. The agreements, which expired on March 31, 2015, were replaced with similar agreements scheduled to expire March 31, 2017. 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 10) 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). 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. The new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. After the FASB's delay in the effective date of the revenue guidance by one year, the Company is required to adopt this guidance in the first quarter of 2018 and early adoption is permitted beginning in the first quarter of 2017. 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 intended to simplify the presentation of debt issuance costs by requiring that such costs be deducted from the carrying amounts related to debt liabilities when presented in the balance sheet. As permitted, the Company expects to early adopt this guidance in the fourth quarter of 2015. The Company does not expect the adoption of this guidance to have a significant impact on its financial position. The guidance will not affect the Company’s results of operations or cash flows. 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 evaluated this guidance and has determined it will not significantly impact the Company’s results of operations, cash flows or financial position. The Company expects to adopt this guidance in the first quarter of 2016. 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.
SCEG
Significant Accounting Policies
Significant Accounting Policies [Text Block]	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles 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. Variable Interest Entities 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 condensed consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. Accordingly, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s condensed consolidated financial statements. GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $489 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 allowances. See also Note 4. 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. In the third quarter of 2015, in connection with the adoption of a customary depreciation study and related analysis, SCE&G determined that these three units would not likely be retired by 2020 (see Note 2), 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 September 30, 2015. 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. The new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. After the FASB's delay in the effective date of the revenue guidance by one year, Consolidated SCE&G is required to adopt this guidance in the first quarter of 2018 and early adoption is permitted beginning in the first quarter of 2017. 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 intended to simplify the presentation of debt issuance costs by requiring that such costs be deducted from the carrying amounts related to debt liabilities when presented in the balance sheet. As permitted, Consolidated SCE&G expects to early adopt this guidance in the fourth quarter of 2015. Consolidated SCE&G does not expect the adoption of this guidance to have a significant impact on its financial position. The guidance will not affect Consolidated SCE&G’s results of operations or cash flows. 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 evaluated this guidance and has determined it will not significantly impact its results of operations, cash flows or financial position. Consolidated SCE&G expects to adopt this guidance in the first quarter of 2016. 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 when presented in the balance sheet. Consolidated SCE&G expects to adopt this guidance 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.

RATE AND OTHER REGULATORY MATTE

RATE AND OTHER REGULATORY MATTERS	9 Months Ended
	Sep. 30, 2015
Rate Matters [Line Items]
Public Utilities Disclosure [Text Block]	RATE AND OTHER REGULATORY MATTERS Rate Matters Electric - Cost of Fuel SCE&G's retail electric rates include a cost of fuel component approved by the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased by SCE&G. Pursuant to an April 2014 SCPSC order, SCE&G increased its base fuel cost component by approximately $10.3 million for the 12-month period beginning with the first billing cycle of May 2014. The base fuel cost increase was offset by a reduction in SCE&G's rate rider related to pension costs approved by the SCPSC in March 2014. In addition, pursuant to the April 2014 order, electric revenue for 2014 was reduced by approximately $46 million for adjustments to the fuel cost component and related under-collected fuel balance. Such adjustments 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 during the period 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, develop renewable energy facilities with a nameplate capacity of at least 84.5 MW by the end of 2020 and have at least 30 MW of utility-scale solar capacity in service by the end of 2016. The order also requires SCE&G to develop incentives for solar energy generated by residential and commercial customers. SCE&G will also make incentives available for residential customers receiving solar power from community solar-programs. 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 resulting in $29 million (or $.12 cents per share) in lower depreciation expense annually. 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 $22 million (or $.09 cents per share) in the third quarter of 2015, and pursuant to the SCPSC order, SCE&G reduced its electric operating revenues by approximately $14.5 million (or $.06 cents per share) with an offset to under-collected fuel included within Receivables in the balance sheet. Accordingly, the Company's net income for each of the three and nine months ended September 30, 2015, increased approximately $4.5 million as a result of this change in estimate. Electric - Base Rates 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 during the three and nine months ended September 30, 2015 totaled $2.4 million and $6.5 million , respectively, and during the three and nine months ended September 30, 2014 totaled $1.6 million and $4.1 million , 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 (see Regulatory Assets and Regulatory Liabilities below) 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. 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 Action Amount 2015 2.6 % Increase $ 64.5 million 2014 2.8 % Increase $ 66.2 million 2013 2.9 % Increase $ 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 9. 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 review conducted for the 12-month period ended July 31, 2014 resulted in the SCPSC issuing an order finding that SCE&G's gas purchasing policies and practices during the review period were reasonable and prudent. SCE&G's 2015 annual PGA hearing was held on November 5, 2015 and the SCPSC's decision is pending. 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 periods than do other enterprises. 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. Millions of dollars September 30, December 31, Regulatory Assets: Accumulated deferred income taxes $ 284 $ 284 Under-collections - electric fuel adjustment clause — 20 Environmental remediation costs 39 40 AROs and related funding 376 366 Franchise agreements 23 26 Deferred employee benefit plan costs 328 350 Planned major maintenance — 2 Deferred losses on interest rate derivatives 538 453 Deferred pollution control costs 35 36 Unrecovered plant 128 137 DSM Programs 59 56 Carrying costs on deferred tax assets related to nuclear construction 15 9 Pipeline integrity management costs 16 9 Other 43 35 Total Regulatory Assets $ 1,884 $ 1,823 Regulatory Liabilities: Accumulated deferred income taxes $ 22 $ 22 Asset removal costs 729 703 Storm damage reserve 6 6 Deferred gains on interest rate derivatives 87 82 Planned major maintenance 12 — Other 3 1 Total Regulatory Liabilities $ 859 $ 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 depreciation and are expected to be recovered over the remaining lives of the related property which may range up to approximately 85 years. Similarly, accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability. Under-collections - electric fuel adjustment clause represent amounts due from customers pursuant to the fuel adjustment clause as approved by the SCPSC which are expected to be recovered in retail electric rates over periods exceeding 12 months. 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. 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. Franchise agreements represent costs associated with electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. Based on an SCPSC order, SCE&G is recovering these amounts through cost of service rates through approximately 2021. 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. Planned major maintenance related to certain fossil fueled turbine/generation equipment and nuclear refueling outages is accrued in periods other than when incurred, pursuant to specific SCPSC orders. SCE&G collects and accrues $18.4 million annually for fossil fueled turbine/generation equipment maintenance, and collects and accrues $17.2 million annually for nuclear-related refueling charges. 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. Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the scrubbers installed at certain coal-fired generating plants pursuant to specific regulatory orders. Such costs are being recovered through utility rates through 2045. 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. 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. Carrying costs on deferred tax assets related to nuclear construction are calculated on accumulated deferred income tax assets associated with the New Units which are not part of electric rate base using the weighted average long-term debt cost of capital. These carrying costs will be amortized over ten years beginning in approximately 2021. Pipeline integrity management costs represent costs incurred to comply with regulatory requirements related to certain natural gas pipelines located near moderate to high density populations. Such costs at SCE&G will be amortized at $1.9 million annually beginning in November 2015. Such costs at PSNC Energy will be considered for recovery through rates in its next general rate proceeding. 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 storm damage reserve represents an SCPSC-approved collection through SCE&G electric rates, capped at $100 million , which can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year. Pursuant to specific regulatory orders, SCE&G has suspended storm damage reserve collection through rates indefinitely. During the nine months ended September 30, 2015, no amounts were applied to offset incremental storm damage costs. 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.
SCEG
Rate Matters [Line Items]
Public Utilities Disclosure [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. 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 during the period 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 its 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, develop renewable energy facilities with a nameplate capacity of at least 84.5 MW by the end of 2020 and have at least 30 MW of utility-scale solar capacity in service by the end of 2016. The order also requires SCE&G to develop incentives for solar energy generated by residential and commercial customers. SCE&G will also make incentives available for residential customers receiving solar power from community solar-programs. 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 resulting in $29 million in lower depreciation expense annually. 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 $22 million in the third quarter of 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, Consolidated SCE&G's net income for each of the three and nine months ended September 30, 2015, increased approximately $4.5 million as a result of this change in estimate. Electric - Base Rates 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 during the three and nine months ended September 30, 2015 totaled $2.4 million and $6.5 million , respectively, and during the three and nine months ended September 30, 2014 totaled $1.6 million and $4.1 million , 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 (see Regulatory Assets and Regulatory Liabilities below) 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. 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 Action Amount 2015 2.6 % Increase $ 64.5 million 2014 2.8 % Increase $ 66.2 million 2013 2.9 % Increase $ 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 9. 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 review conducted for the 12-month period ended July 31, 2014 resulted in the SCPSC issuing an order finding that SCE&G's gas purchasing policies and practices during the review period were reasonable and prudent. SCE&G's 2015 annual PGA hearing was held on November 5, 2015 and the SCPSC's decision is pending. 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 periods than do other enterprises. 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. Millions of dollars September 30, December 31, Regulatory Assets: Accumulated deferred income taxes $ 278 $ 278 Under collections – electric fuel adjustment clause — 20 Environmental remediation costs 35 36 AROs and related funding 356 347 Franchise agreements 23 26 Deferred employee benefit plan costs 296 310 Planned major maintenance — 2 Deferred losses on interest rate derivatives 538 453 Deferred pollution control costs 35 36 Unrecovered plant 128 137 DSM Programs 59 56 Carrying costs on deferred tax assets related to nuclear construction 15 9 Other 45 35 Total Regulatory Assets $ 1,808 $ 1,745 Regulatory Liabilities: Accumulated deferred income taxes $ 16 $ 17 Asset removal costs 520 505 Storm damage reserve 6 6 Deferred gains on interest rate derivatives 87 82 Planned major maintenance 12 — Total Regulatory Liabilities $ 641 $ 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 depreciation and are expected to be recovered over the remaining lives of the related property which may range up to approximately 85 years. Similarly, accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability. Under-collections - electric fuel adjustment clause represent amounts due from customers pursuant to the fuel adjustment clause as approved by the SCPSC which are expected to be recovered in retail electric rates over periods exceeding 12 months. 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 recovered over periods of up to approximately 24 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. Franchise agreements represent costs associated with electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. Based on an SCPSC order, SCE&G is recovering these amounts through cost of service rates through approximately 2021. 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. Planned major maintenance related to certain fossil fueled turbine/generation equipment and nuclear refueling outages is accrued in periods other than when incurred, pursuant to specific SCPSC orders. SCE&G collects and accrues $18.4 million annually for fossil fueled turbine/generation equipment maintenance and collects and accrues $17.2 million annually for nuclear-related refueling charges. 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. Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the scrubbers installed at certain coal-fired generating plants pursuant to specific regulatory orders. Such costs are being recovered through utility rates through 2045. 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 2025. Unamortized amounts are included in rate base and are earning a current return. 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. Carrying costs on deferred tax assets related to nuclear construction are calculated on accumulated deferred income tax assets associated with the New Units which are not part of electric rate base using the weighted average long-term debt cost of capital. These carrying costs will be amortized over ten years beginning in approximately 2021. 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 storm damage reserve represents an SCPSC-approved collection through SCE&G electric rates, capped at $100 million , which can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year. Pursuant to specific regulatory orders, SCE&G has suspended storm damage reserve collection through rates indefinitely. During the nine months ended September 30, 2015, no amounts were applied to offset incremental storm damage costs. 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	9 Months Ended
	Sep. 30, 2015
Schedule of Capitalization, Equity [Line Items]
Stockholders' Equity Note Disclosure [Text Block]	COMMON EQUITY Changes in common equity during the nine months ended September 30, 2015 and 2014 were as follows: Common Stock Accumulated Other Comprehensive Income (Loss) Millions Shares Outstanding Amount Treasury Shares Retained Earnings Gains(Losses) on Cash Flow Hedges Deferred Employee Benefit Plans Total AOCI Total Common Equity Balance as of January 1, 2015 143 $ 2,388 $ (10 ) $ 2,684 $ (63 ) $ (12 ) $ (75 ) $ 4,987 Net Income 648 648 Other Comprehensive Income (Loss): Losses during the period (8 ) (3 ) (11 ) (11 ) Reclassified from AOCI 16 — 16 16 Total Comprehensive Income (Loss) 648 8 (3 ) 5 653 Issuance of Common Stock — 14 (1 ) 13 Dividends Declared (234 ) (234 ) Balance as of September 30, 2015 143 $ 2,402 $ (11 ) $ 3,098 $ (55 ) $ (15 ) $ (70 ) $ 5,419 Balance as of January 1, 2014 141 $ 2,289 $ (9 ) $ 2,444 $ (52 ) $ (8 ) $ (60 ) $ 4,664 Net Income 433 433 Other Comprehensive Income: Losses during the period (3 ) — (3 ) (3 ) Reclassified from AOCI 1 1 2 2 Total Comprehensive Income 433 (2 ) 1 (1 ) 432 Issuance of Common Stock 1 76 (1 ) 75 Dividends Declared (223 ) (223 ) Balance as of September 30, 2014 142 $ 2,365 $ (10 ) $ 2,654 $ (54 ) $ (7 ) $ (61 ) $ 4,948 Gains and losses on cash flow hedges reclassified during the nine months ended September 30, 2015 resulted in higher interest expense of $6 million and higher cost of gas purchased for resale of $10 million . Such reclassifications during the comparable period in 2014 resulted in higher interest expense of $5 million and lower cost of gas purchased for resale of $4 million . SCANA had 200 million shares of common stock authorized as of September 30, 2015 and December 31, 2014.
SCEG
Schedule of Capitalization, Equity [Line Items]
Stockholders' Equity Note Disclosure [Text Block]	EQUITY Changes in common equity during the nine months ended September 30, 2015 and 2014 were as follows: Common Stock Retained Accumulated Other Comprehensive Noncontrolling Total Millions Shares Amount Earnings Income (Loss) Interest Equity Balance at January 1, 2015 40 $ 2,560 $ 2,077 $ (3 ) $ 123 $ 4,757 Earnings available to common shareholder 394 11 405 Deferred cost of employee benefit plans — — Total Comprehensive Income 394 — 11 405 Capital contributions from parent 196 196 Cash dividend declared (205 ) (5 ) (210 ) Balance at September 30, 2015 40 $ 2,756 $ 2,266 $ (3 ) $ 129 $ 5,148 Balance at January 1, 2014 40 $ 2,479 $ 1,896 $ (3 ) $ 117 $ 4,489 Earnings available to common shareholder 374 9 383 Deferred cost of employee benefit plans — — Total Comprehensive Income 374 — 9 383 Capital contributions from parent 82 82 Cash dividend declared (192 ) (5 ) (197 ) Balance at September 30, 2014 40 $ 2,561 $ 2,078 $ (3 ) $ 121 $ 4,757 SCE&G had 50 million shares of common stock authorized as of September 30, 2015 and December 31, 2014. SCE&G had 20 million shares of preferred stock authorized as of September 30, 2015 and December 31, 2014, of which 1,000 shares at a stated value of $100,000 were issued and outstanding during all periods presented. All issued and outstanding shares of SCE&G's common and preferred stock are held by SCANA. Reclassifications from AOCI into earnings of the amortization of deferred employee benefit costs were not significant for any period presented.

LONG-TERM AND SHORT-TERM DEBT

LONG-TERM AND SHORT-TERM DEBT	9 Months Ended
	Sep. 30, 2015
Debt Instrument [Line Items]
Long-term Debt [Text Block]	LONG-TERM DEBT AND LIQUIDITY Long-term Debt 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. On February 2, 2015, SCANA redeemed prior to maturity $150 million of its 7.7% junior subordinated notes at their face value. 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. Substantially all electric utility plant is pledged as collateral in connection with long-term debt. Liquidity SCANA, SCE&G (including Fuel Company) and PSNC Energy had available the following committed LOC, and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations: SCANA SCE&G PSNC Energy Millions of dollars September 30, December 31, September 30, December 31, September 30, December 31, Lines of credit: Total committed long-term $ 300 $ 300 $ 1,400 $ 1,400 $ 100 $ 100 Outstanding commercial paper ( 270 or fewer days) $ 14 $ 179 $ 234 $ 709 $ 16 $ 30 Weighted average interest rate 0.66 % 0.54 % 0.44 % 0.52 % 0.45 % 0.65 % Letters of credit supported by LOC $ 3 $ 3 $ 0.3 $ 0.3 — — Available $ 283 $ 118 $ 1,166 $ 691 $ 84 $ 70 SCANA, SCE&G (including Fuel Company) and PSNC Energy are parties to five-year credit agreements in the amounts of $300 million , $1.2 billion (of which $500 million relates to Fuel Company) and $100 million , respectively, which expire in October 2019. In addition, SCE&G is a party to a three-year credit agreement in the amount of $200 million , which expires in October 2016. 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 10.7% of the aggregate $1.8 billion credit facilities, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A., Credit Suisse AG, Cayman Island Branch and UBS Loan Finance LLC each provide 8.9% , and Branch Banking and Trust Company, Union Bank, N.A. and U.S. Bank National Association each provide 6.3% . 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. 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. These letters of credit expire, subject to renewal, in the fourth quarter of 2019.
SCEG
Debt Instrument [Line Items]
Long-term Debt [Text Block]	LONG-TERM DEBT AND LIQUIDITY Long-term Debt 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. 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. Substantially all electric utility plant is pledged as collateral in connection with long-term debt. Liquidity SCE&G (including Fuel Company) had available the following committed LOC, and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations: Millions of dollars September 30, December 31, Lines of credit: Total committed long-term $ 1,400 $ 1,400 Outstanding commercial paper (270 or fewer days) $ 234 $ 709 Weighted average interest rate 0.44 % 0.52 % Letters of credit supported by LOC $ 0.3 $ 0.3 Available $ 1,166 $ 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), which expire in October 2019. In addition, SCE&G is a party to a three-year credit agreement in the amount of $200 million , which expires in October 2016. 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 10.7% of the aggregate $1.4 billion credit facilities, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A., Credit Suisse AG, Cayman Islands Branch and UBS Loan Finance LLC each provide 8.9% and Branch Banking and Trust Company, Union Bank, N.A. and U.S. Bank National Association each provide 6.3% . 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 September 30, 2015, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $41.2 million . At December 31, 2014, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $83.0 million and money pool investments due from an affiliate of $80.0 million .

INCOME TAXES

INCOME TAXES	9 Months Ended
	Sep. 30, 2015
income tax [Line Items]
Income Tax Disclosure [Text Block]	INCOME TAXES Between 2013 and 2015, in addition to filing current year tax returns, the Company amended certain of its tax returns. These returns claimed certain tax-defined research and development deductions and credits. In connection with these filings, the Company recorded an unrecognized tax benefit of $18 million . If recognized, $14 million of the tax benefit would affect the Company’s effective tax rate. It is reasonably possible that this tax benefit will increase by an additional $2 million within the next 12 months. It is also reasonably possible that this tax benefit 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 September 30, 2015. The Company recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses. The Company has not recorded any interest expense or penalties associated with these positions.
SCEG
income tax [Line Items]
Income Tax Disclosure [Text Block]	INCOME TAXES Between 2013 and 2015, in addition to filing current year tax returns, SCANA amended certain of its tax returns. These returns claimed certain tax-defined research and development deductions and credits. In connection with these filings, Consolidated SCE&G recorded an unrecognized tax benefit of $18 million . If recognized, $14 million of the tax benefit would affect Consolidated SCE&G’s effective tax rate. It is reasonably possible that this tax benefit will increase by an additional $2 million within the next 12 months. It is also reasonably possible that this tax benefit 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 September 30, 2015. Consolidated SCE&G recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses. Consolidated SCE&G has not recorded any interest expense or penalties associated with these positions.

DERIVATIVE FINANCIAL INSTRUMENT

DERIVATIVE FINANCIAL INSTRUMENTS	9 Months Ended
	Sep. 30, 2015
Derivative [Line Items]
Derivative Instruments and Hedging Activities Disclosure [Text Block]	DERIVATIVE FINANCIAL INSTRUMENTS The Company recognizes all derivative instruments as either assets or liabilities in the statement 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 OCI 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 condensed consolidated statements of cash flows. PSNC Energy hedges natural gas purchasing activities using over-the-counter options and NYMEX futures and options. PSNC Energy’s tariffs include a provision for the recovery of actual gas costs incurred, including any costs of hedging. PSNC Energy records premiums, transaction fees, margin requirements and any realized gains or losses from its hedging program in deferred accounts as a regulatory asset or liability for the under- or over-recovery of gas costs. These derivative financial instruments are not designated as hedges for accounting purposes. Unrealized gains and losses on qualifying cash flow hedges of nonregulated operations are deferred in AOCI. When the hedged transactions affect earnings, previously recorded gains and losses are reclassified from AOCI to cost of gas. The effects of gains or losses resulting from these hedging activities are either offset by the recording of the related hedged transactions or are included in gas sales pricing decisions made by the business unit. As an accommodation to certain customers, 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. 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 locks or forward starting swap agreements that are designated as cash flow hedges. For GENCO, the effective portions of changes in fair value and payments made or received upon termination of such agreements 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 rate derivatives entered into by SCE&G after October 2013 are not designated as cash flow hedges, and all related fair value changes and settlement amounts are recorded as regulatory assets or liabilities. Interest rate derivatives entered into before October 2013 were designated as cash flow hedges, and for such instruments only the effective portion of fair value changes and settlement amounts are recorded in regulatory assets or regulatory liabilities. Upon settlement, losses on swaps are amortized over the lives of related debt issuances, and gains are applied to under-collected fuel, are amortized to interest expense or are applied as otherwise directed by the SCPSC. Cash payments made or received upon termination of these financial instruments are classified as investing activities for cash flow statement purposes. Quantitative Disclosures Related to Derivatives The Company was party to natural gas derivative contracts outstanding in the following quantities: Commodity and Other Energy Management Contracts (in MMBTU) Hedge designation Gas Distribution Retail Gas Marketing Energy Marketing Total As of September 30, 2015 Commodity contracts 9,270,000 11,788,000 4,335,500 25,393,500 Energy management contracts (a) — — 32,211,282 32,211,282 Total (a) 9,270,000 11,788,000 36,546,782 57,604,782 As of December 31, 2014 Commodity contracts 6,840,000 7,951,000 3,446,720 18,237,720 Energy management contracts (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 1,246,230 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 September 30, 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 $1.2 billion at September 30, 2015 and $1.1 billion at December 31, 2014. The fair value of interest rate and energy-related derivatives was as follows: Fair Values of Derivative Instruments Millions of dollars Balance Sheet Location Asset Liability As of September 30, 2015 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 4 Other deferred credits and other liabilities 31 Commodity contracts Other current assets 1 Derivative financial instruments 6 Total $ 42 Not designated as hedging instruments Interest rate contracts Other deferred debits and other assets $ 6 — Derivative financial instruments — $ 107 Other deferred credits and other liabilities — 60 Energy management contracts Other current assets 10 2 Derivative financial instruments — 8 Other deferred debits and other assets 5 — Other deferred credits and other liabilities — 4 Total $ 21 $ 181 Millions of dollars Balance Sheet Location Asset Liability 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 Derivative financial instruments — 10 Other deferred debits and other assets 5 — Other deferred credits and other liabilities — 5 Total $ 21 $ 244 The effect of derivative instruments on the condensed consolidated statements of income is as follows: 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 Loss Deferred in Regulatory Accounts Loss Reclassified from Deferred Accounts into Income (Effective Portion) (Effective Portion) Millions of dollars 2015 2014 Location 2015 2014 Three Months Ended September 30, Interest rate contracts $ (3 ) $ (1 ) Interest expense $ (1 ) $ (1 ) Nine Months Ended September 30, Interest rate contracts $ (3 ) $ (5 ) Interest expense $ (2 ) $ (2 ) Gain (Loss) Recognized in OCI, net of tax Gain (Loss) Reclassified from AOCI into Income, net of tax (Effective Portion) (Effective Portion) Millions of dollars 2015 2014 Location 2015 2014 Three Months Ended September 30, Interest rate contracts $ (3 ) — Interest expense $ (2 ) $ (2 ) Commodity contracts (4 ) $ (2 ) Gas purchased for resale (1 ) — Total $ (7 ) $ (2 ) $ (3 ) $ (2 ) Nine Months Ended September 30, Interest rate contracts $ (3 ) $ (4 ) Interest expense $ (6 ) $ (5 ) Commodity contracts (5 ) 1 Gas purchased for resale (10 ) 4 Total $ (8 ) $ (3 ) $ (16 ) $ (1 ) As of September 30, 2015, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $4.0 million as an increase to gas cost and approximately $6.5 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels. As of September 30, 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 September 30, 2015, the Company expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $2.3 million as an increase to interest expense, assuming financial markets remain at their current levels. Hedge Ineffectiveness Ineffectiveness on interest rate hedges designated as cash flow hedges was insignificant during all periods presented. Derivatives not designated as Hedging Instruments Loss Deferred in Regulatory Accounts Gain Reclassified from Deferred Accounts into Income Millions of dollars 2015 2014 Location 2015 2014 Three Months Ended September 30, Interest rate contracts $ (116 ) $ (35 ) Other income — $ 5 Nine Months Ended September 30, Interest rate contracts $ (79 ) $ (220 ) Other income $ 5 $ 60 As of September 30, 2015, the Company expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from derivatives not designated as hedges will include $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. The Company uses standardized master agreements which may 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 permit the secured party to demand the posting of 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 may require the Company to provide collateral upon the occurrence of specific events, primarily credit downgrades. As of September 30, 2015 and December 31, 2014, the Company had posted $148.4 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 condensed consolidated balance sheets. Collateral related to noncurrent positions is recorded in Other within Deferred Debits and Other Assets on the condensed consolidated balance sheets. If all of the contingent features underlying these instruments had been fully triggered as of September 30, 2015 and December 31, 2014, the Company could have been required to post an additional $69.1 million and $129.8 million , respectively, of collateral with its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of September 30, 2015 and December 31, 2014 is $217.5 million and $282.2 million , respectively. In addition, as of September 30, 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 September 30, 2015 and December 31, 2014, the Company could request $2.8 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 September 30, 2015 and December 31, 2014 is $2.8 million and $- million, respectively. In addition, as of September 30, 2015, the Company could have called on letters of credit in the amount of $3.0 million related to $15.0 million in commodity derivatives that are in a net asset position, compared to letters of credit of $9.2 million related to derivatives of $20.0 million at December 31, 2014, if all the contingent features underlying these instruments had been fully triggered. Information related to the Company's offsetting of derivative assets follows: Gross Amounts of Recognized 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 Financial Instruments Cash Collateral Received As of September 30, 2015 Interest rate contracts $ 6 — $ 6 $ (3 ) — $ 3 Energy management contracts 15 — 15 — — 15 Total $ 21 — $ 21 $ (3 ) — $ 18 Balance sheet location Other current assets $ 10 Other deferred debits and other assets 11 Total $ 21 As of December 31, 2014 Commodity contracts $ 1 — $ 1 — — $ 1 Energy management contracts 20 — 20 — — 20 Total $ 21 — $ 21 — — $ 21 Balance sheet location Other current assets $ 16 Other deferred debits and other assets 5 Total $ 21 Information related to the Company's offsetting of derivative liabilities follows: Gross Amounts of Recognized 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 Financial Instruments Cash Collateral Posted As of September 30, 2015 Interest rate contracts $ 202 — $ 202 $ (3 ) $ (135 ) $ 64 Commodity contracts 7 — 7 — (6 ) 1 Energy management contracts 14 — 14 — (7 ) 7 Total $ 223 — $ 223 $ (3 ) $ (148 ) $ 72 Balance sheet location Other current assets $ 3 Derivative financial instruments 125 Other deferred credits and other liabilities 95 Total $ 223 As of December 31, 2014 Interest rate contracts $ 257 — $ 257 — $ (131 ) $ 126 Commodity contracts 12 — 12 — (10 ) 2 Energy management contracts 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
SCEG
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 the statement 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 locks or forward starting swap agreements. Pursuant to regulatory orders, interest rate derivatives entered into by SCE&G after October 2013 are not designated as cash flow hedges, and all related fair value changes and settlement amounts are recorded as regulatory assets or liabilities. Interest rate derivatives entered into by SCE&G before October 2013, and all such derivatives entered into by GENCO, were designated as cash flow hedges, and for such instruments only the effective portion of fair value changes and settlement amounts are recorded in regulatory assets or regulatory liabilities. Upon settlement, losses on swaps are amortized over the lives of related debt issuances, and gains are applied to under-collected fuel, are amortized to interest expense or are applied as otherwise directed by the SCPSC. Cash payments made or received upon termination of these financial instruments are classified as investing activities for cash flow statement purposes. Quantitative Disclosures Related to Derivatives GENCO was party to an interest rate swap designated as a cash flow hedge with a notional amount of $36.4 million at September 30, 2015 and $36.4 million at December 31, 2014. SCE&G was party to interest rate swaps not designated as cash flow hedges with an aggregate notional amount of $1.2 billion at September 30, 2015 and $1.1 billion at December 31, 2014, respectively. The fair value of interest rate derivatives was as follows: Fair Values of Derivative Instruments Fair Value Millions of dollars Balance Sheet Location Asset Liability As of September 30, 2015 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 1 Other deferred credits and other liabilities 10 Total $ 11 Not designated as hedging instruments Interest rate contracts Derivative financial instruments — $ 107 Other deferred debits and other assets $ 6 Other deferred credits and other liabilities — 60 Total $ 6 $ 167 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 condensed consolidated statement of income is as follows: Derivatives in Cash Flow Hedging Relationships Loss Deferred in Regulatory Accounts Loss Reclassified from Deferred Accounts into Income (Effective Portion) (Effective Portion) Millions of dollars 2015 2014 Location 2015 2014 Three Months Ended September 30, Interest rate contracts $ (3 ) $ (1 ) Interest expense $ (1 ) $ (1 ) Nine Months Ended September 30, Interest rate contracts $ (3 ) $ (5 ) Interest expense $ (2 ) $ (2 ) As of September 30, 2015, Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $2.3 million as an increase to interest expense, assuming financial markets remain at their current levels. Hedge Ineffectiveness Ineffectiveness on interest rate hedges designated as cash flow hedges was insignificant during all periods presented. Derivatives not designated as Hedging Instruments Loss Deferred in Regulatory Accounts Gain Reclassified from Deferred Accounts into Income Millions of dollars 2015 2014 Location 2015 2014 Three Months Ended September 30, Interest rate contracts $ (116 ) $ (35 ) Other income — $ 5 Nine Months Ended September 30, Interest rate contracts $ (79 ) $ (220 ) Other income $ 5 $ 60 As of September 30, 2015, Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from derivatives not designated as hedges will include $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. Consolidated SCE&G uses standardized master agreements which may 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 permit the secured party to demand the posting of 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 may require Consolidated SCE&G to provide collateral upon the occurrence of specific events, primarily credit downgrades. As of September 30, 2015 and December 31, 2014, Consolidated SCE&G had posted $108.9 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 condensed consolidated balance sheets. Collateral related to noncurrent positions is recorded in Other within Deferred Debits and Other Assets on the condensed consolidated balance sheets. If all of the contingent features underlying these instruments had been fully triggered as of September 30, 2015 and December 31, 2014, Consolidated SCE&G could have been required to post an additional $65.8 million and $125.9 million , respectively, of collateral with its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of September 30, 2015 and December 31, 2014 is $174.7 million and $233.0 million , respectively. In addition, as of September 30, 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 September 30, 2015 and December 31, 2014, Consolidated SCE&G could request $2.8 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 September 30, 2015 and December 31, 2014 is $2.8 million and $- million, respectively. Information related to Consolidated SCE&G's derivative assets follows: Gross Amounts of Recognized 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 Financial Instruments Cash Collateral Received As of September 30, 2015 Interest rate contracts $ 6 — $ 6 $ (3 ) — $ 3 Balance Sheet Location Other deferred debits and other assets $ 6 As of December 31, 2014, Consolidated SCE&G had no derivative assets. Information related to Consolidated SCE&G's derivative liabilities follows: Gross Amounts of Recognized 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 Financial Instruments Cash Collateral Posted As of September 30, 2015 Interest rate contracts $ 178 — $ 178 $ (3 ) $ (109 ) $ 66 Balance Sheet Location Derivative financial instruments $ 108 Other deferred credits and other liabilities 70 Total $ 178 As of December 31, 2014 Interest rate contracts $ 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	9 Months Ended
	Sep. 30, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Disclosures [Text Block]	FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES The Company 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 September 30, 2015 As of December 31, 2014 Millions of dollars Level 1 Level 2 Level 1 Level 2 Assets: Available for sale securities $ 13 — $ 13 — Interest rate contracts — $ 6 — — Commodity contracts — — 1 — Energy management contracts — 15 — $ 20 Liabilities: Interest rate contracts — 202 — 257 Commodity contracts 1 6 1 11 Energy management contracts 2 15 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 were as follows: September 30, 2015 December 31, 2014 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Long-term debt $ 6,034.3 $ 6,623.3 $ 5,697.2 $ 6,592.1 Fair values of long-term debt instruments are based on net present value calculations using independently sourced market data that incorporate a developed discount rate using similarly rated long-term debt, along with benchmark interest rates. As such, the aggregate fair values presented above are considered to be Level 2. Early settlement of long-term debt may not be possible or may not be considered prudent. Carrying values of short-term borrowings approximate fair value, and are based on quoted prices from dealers in the commercial paper market. The resulting fair value is considered to be Level 2.
SCEG
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Disclosures [Text Block]	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: Millions of dollars September 30, 2015 December 31, 2014 Assets - Interest rate contracts $ 6 — Liabilities - Interest rate contracts 178 $ 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 were as follows: September 30, 2015 December 31, 2014 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Long-term debt $ 4,801.0 $ 5,277.6 $ 4,308.6 $ 5,070.9 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 fair value, and are based on quoted prices from dealers in the commercial paper market. The resulting fair value is considered to be Level 2.

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS	9 Months Ended
	Sep. 30, 2015
Pension and Other Postretirement Benefit Plans
EMPLOYEE BENEFIT PLANS	EMPLOYEE BENEFIT PLANS Components of net periodic benefit cost recorded by the Company were as follows: Pension Benefits Other Postretirement Benefits Millions of dollars 2015 2014 2015 2014 Three months ended September 30, Service cost $ 6.6 $ 5.0 $ 1.2 $ 0.9 Interest cost 9.6 9.9 2.8 2.8 Expected return on assets (15.5 ) (16.4 ) — — Prior service cost amortization 1.0 1.1 0.1 0.1 Amortization of actuarial losses (gains) 3.2 0.9 0.4 (0.2 ) Net periodic benefit cost $ 4.9 $ 0.5 $ 4.5 $ 3.6 Nine months ended September 30, Service cost $ 18.1 $ 15.0 $ 4.0 $ 3.4 Interest cost 28.7 30.3 8.6 9.0 Expected return on assets (46.5 ) (50.0 ) — — Prior service cost amortization 3.0 3.1 0.3 0.3 Amortization of actuarial losses 10.2 3.5 1.5 — Net periodic benefit cost $ 13.5 $ 1.9 $ 14.4 $ 12.7 No significant contribution to the pension trust is expected for the foreseeable future, nor is a limitation on benefit payments expected to apply. SCE&G recovers current pension costs through either a rate rider that may be adjusted annually for retail electric operations or through cost of service rates for gas operations.
SCEG
Pension and Other Postretirement Benefit Plans
EMPLOYEE BENEFIT PLANS	EMPLOYEE BENEFIT PLANS Consolidated SCE&G participates in SCANA’s noncontributory defined benefit pension plan, which covers the majority of all regular, full-time employees, and also participates in SCANA’s unfunded postretirement health care and life insurance programs, which provide benefits to retired employees. Components of net periodic benefit cost recorded by Consolidated SCE&G were as follows: Pension Benefits Other Postretirement Benefits Millions of dollars 2015 2014 2015 2014 Three months ended September 30, Service cost $ 5.3 $ 4.0 $ 1.0 $ 0.7 Interest cost 8.1 8.4 2.2 2.3 Expected return on assets (13.0 ) (13.9 ) — — Prior service cost amortization 0.8 0.9 0.1 — Amortization of actuarial losses (gains) 2.7 0.8 0.3 (0.2 ) Net periodic benefit cost $ 3.9 $ 0.2 $ 3.6 $ 2.8 Nine months ended September 30, Service cost $ 14.5 $ 12.0 $ 3.2 $ 2.7 Interest cost 24.1 25.6 6.8 7.1 Expected return on assets (39.1 ) (42.2 ) — — Prior service cost amortization 2.5 2.6 0.2 0.2 Amortization of actuarial losses 8.6 3.0 1.2 — Net periodic benefit cost $ 10.6 $ 1.0 $ 11.4 $ 10.0 No significant contribution to the pension trust is expected for the foreseeable future, nor is a limitation on benefit payments expected to apply. SCE&G recovers current pension costs through either a rate rider that may be adjusted annually for retail electric operations or through cost of service rates for gas operations.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	9 Months Ended
	Sep. 30, 2015
Statement [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 SCE&G's nuclear power plant. Price-Anderson provides funds up to $12.9 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 in limits of accidental property damage occurring during construction. The NEIL policies, in the aggregate, are subject to a maximum loss of $2.75 billion for any single loss occurrence. All of the NEIL policies permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $45.9 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's rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G has no reason to anticipate a serious nuclear 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, under an agreement signed in January 2014 (and subject to customary closing conditions, including necessary regulatory approvals), 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 schedule 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 September 30, 2015, SCE&G’s investment in the New Units, including related transmission, totaled $3.3 billion , for which the financing costs on $2.4 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, including those related to fabrication and delivery of sub-modules for the New Units. The fabrication and delivery of sub-modules have been and remain focus areas of the Consortium. Shield building panels are considered critical path items for both New Units, and the current schedule for production of such panels will require mitigation to support the updated substantial completion dates (see 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. 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 will become effective upon the consummation of the acquisition by WEC of the stock of Stone & Webster from CB&I, and will become null and void in the event such acquisition is not consummated by March 31, 2016. Following that acquisition, Stone & Webster will continue to be a member of the Consortium as a subsidiary of WEC rather than CB&I, and WEC intends to engage Fluor Corporation or its affiliate(s) as a subcontracted construction manager. Among other things, upon effectiveness, the October 2015 Amendment would (i) resolve 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) revise the guaranteed substantial completion dates of Units 2 and 3 to August 31, 2019 and 2020, respectively, (iii) revise 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 cap those aggregate liquidated damages at $463 million per New Unit (SCE&G’s 55% portion being approximately $255 million per New Unit), (iv) provide 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) provide for the 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) provide that SCE&G and Santee Cooper waive and cancel the CB&I parent company guaranty with respect to the project. The payment obligations under the EPC Contract are joint and several obligations of WEC and Stone & Webster, and the October 2015 Amendment provides for Toshiba Corporation, WEC’s parent company, to reaffirm its guaranty of WEC’s payment obligations. Under the October 2015 Amendment, SCE&G’s total estimated project costs will increase by approximately $286 million over the $6.8 billion approved by the SCPSC in September 2015, and will bring its total estimated gross construction cost of the project (including escalation and AFC) to approximately $7.1 billion . In addition to the above, upon effectiveness, the October 2015 Amendment would provide for an explicit definition of a Change in Law designed to reduce the likelihood of certain future commercial disputes. As part of this, the Consortium would also acknowledge and agree 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 would also establish 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 would also be revised to eliminate the requirement or ability to bring suit before substantial completion of the project. Finally, upon effectiveness, the October 2015 Amendment would provide 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 amount 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 amounts 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 expects to hold 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, as provided under the BLRA, for an update to the project’s estimated capital cost schedule which would incorporate the impact of this 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 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 current milestone schedule and capital costs schedule approved by the SCPSC in September 2015 and without considering the October 2015 Amendment discussed above, SCE&G’s estimated cost would be approximately $750 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 integrated response 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 carbon 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 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, thus delaying 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. 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 ruling, however, is not expected to have an impact on SCE&G or GENCO due to the aforementioned retirements and conversions. 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 becomes 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 September 30, 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 is constructing 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 $19.0 million , which is accrued in Other within Deferred Credits and Other Liabilities on the condensed consolidated balance sheet. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates. At September 30, 2015, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $34.7 million and are included in regulatory assets. 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 legal obligations associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation relate primarily to the Company’s utility operations. As of September 30, 2015 and December 31, 2014, the Company has recorded AROs of approximately $174 million and $201 million , respectively, for nuclear plant decommissioning and AROs of approximately $315 million and $362 million , respectively, 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 carrying amount of asset retirement obligations is as follows: Millions of dollars September 30, 2015 December 31, 2014 Beginning balance $ 563 $ 576 Liabilities incurred — 3 Liabilities settled (15 ) (6 ) Accretion expense 20 26 Revisions in estimated cash flows (79 ) (36 ) Ending balance $ 489 $ 563 Revisions in estimated cash flows during 2015 primarily relate to changes in the expected timing of settlement of AROs in light of changes in the estimated useful lives of certain electric utility properties identified as part of a customary depreciation study.
SCEG
Statement [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 SCE&G's nuclear power plant. Price-Anderson provides funds up to $12.9 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 in limits of accidental property damage occurring during construction. The NEIL policies, in the aggregate, are subject to a maximum loss of $2.75 billion for any single loss occurrence. All of the NEIL policies permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $45.9 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's rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G has no reason to anticipate a serious nuclear incident. However, if such an incident were to occur, it likely would have a material impact on 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, under an agreement signed in January 2014 (and subject to customary closing conditions, including necessary regulatory approvals), 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 schedule 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 September 30, 2015, SCE&G’s investment in the New Units, including related transmission, totaled $3.3 billion , for which the financing costs on $2.4 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, including those related to fabrication and delivery of sub-modules for the New Units. The fabrication and delivery of sub-modules have been and remain focus areas of the Consortium. Shield building panels are considered critical path items for both New Units, and the current schedule for production of such panels will require mitigation to support the updated substantial completion dates (see 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. 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 11.00% to 10.50%. 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 will become effective upon the consummation of the acquisition by WEC of the stock of Stone & Webster from CB&I, and will become null and void in the event such acquisition is not consummated by March 31, 2016. Following that acquisition, Stone & Webster will continue to be a member of the Consortium as a subsidiary of WEC rather than CB&I, and WEC intends to engage Fluor Corporation or its affiliate(s) as a subcontracted construction manager. Among other things, upon effectiveness, the October 2015 Amendment would (i) resolve 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) revise the guaranteed substantial completion dates of Units 2 and 3 to August 31, 2019 and 2020, respectively, (iii) revise 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 cap those aggregate liquidated damages at $463 million per New Unit (SCE&G’s 55% portion being approximately $255 million per New Unit), (iv) provide 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) provide for the 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) provide that SCE&G and Santee Cooper waive and cancel the CB&I parent company guaranty with respect to the project. The payment obligations under the EPC Contract are joint and several obligations of WEC and Stone & Webster, and the October 2015 Amendment provides for Toshiba Corporation, WEC’s parent company, to reaffirm its guaranty of WEC’s payment obligations. Under the October 2015 Amendment, SCE&G’s total estimated project costs will increase by approximately $286 million over the $6.8 billion approved by the SCPSC in September 2015, and will bring its total estimated gross construction cost of the project (including escalation and AFC) to approximately $7.1 billion . In addition to the above, upon effectiveness, the October 2015 Amendment would provide for an explicit definition of a Change in Law designed to reduce the likelihood of certain future commercial disputes. As part of this, the Consortium would also acknowledge and agree 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 would also establish 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 would also be revised to eliminate the requirement or ability to bring suit before substantial completion of the project. Finally, upon effectiveness, the October 2015 Amendment would provide 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 amount 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 amounts 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 expects to hold 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, as provided under the BLRA, for an update to the project’s estimated capital cost schedule which would incorporate the impact of this 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 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 current milestone schedule and capital costs schedule approved by the SCPSC in September 2015 and without considering the October 2015 Amendment discussed above, SCE&G’s estimated cost would be approximately $750 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 integrated response 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 carbon 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. SCE&G and GENCO are evaluating the final rule, but do not plan to construct new coal-fired units in the foreseeable future. In addition, on August 3, 2015, the EPA issued its final rule on emission guidelines for states to follow in developing plans to address GHG emissions from existing units. The rule includes state-specific goals for reducing national 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. 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, thus delaying 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 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. 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 ruling, however, is not expected to have an impact on SCE&G or GENCO due to the aforementioned retirements and conversions. 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 becomes 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 also 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 September 30, 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 is constructing 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 at least through 2017 and will cost an additional $19.0 million , which is accrued in Other within Deferred Credits and Other Liabilities on the condensed consolidated balance sheet. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates. At September 30, 2015, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $34.7 million and are included in regulatory assets. 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 utility operations. As of September 30, 2015 and December 31, 2014, Consolidated SCE&G has recorded AROs of approximately $174 million and $201 million , respectively, for nuclear plant decommissioning and AROs of approximately $286 million and $335 million , respectively, 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 carrying amount of asset retirement obligations is as follows: Millions of dollars September 30, 2015 December 31, 2014 Beginning balance $ 536 $ 547 Liabilities incurred — 3 Liabilities settled (15 ) (6 ) Accretion expense 18 25 Revisions in estimated cash flows (79 ) (33 ) Ending balance $ 460 $ 536 Revisions in estimated cash flows during 2015 primarily relate to changes in the expected timing of settlement of AROs in light of changes in the estimated useful lives of certain electric utility properties identified as part of a customary depreciation study.

SEGMENT OF BUSINESS INFORMATION

SEGMENT OF BUSINESS INFORMATION	9 Months Ended
	Sep. 30, 2015
Segment Reporting Information [Line Items]
Segment Reporting Disclosure [Text Block]	SEGMENT OF BUSINESS INFORMATION The Company’s reportable segments are listed in the following table. The Company uses operating income to measure profitability for its regulated operations; therefore, net income is not allocated to the Electric Operations and Gas Distribution segments. The Company uses net income to measure profitability for its Retail Gas Marketing and Energy Marketing segments. Gas Distribution is comprised of the local distribution operations of SCE&G and PSNC Energy which meet the criteria for aggregation. All Other includes the parent company, a services company and other nonreportable segments that were insignificant for all periods presented. In addition, All Other includes gains from the sales of CGT and SCI (see Note 11) and their operating results and assets prior to their sale in the first quarter of 2015. CGT and SCI were nonreportable segments during all periods presented. For the period ended September 30, 2015, operating income and net income for All Other include $235 million and $201 million , respectively, related to the sales of CGT and SCI. External revenue and intersegment revenue for All Other related to CGT and SCI were not significant during any period presented. Millions of dollars External Revenue Intersegment Revenue Operating Income Net Income Three Months Ended September 30, 2015 Electric Operations $ 742 $ 1 $ 313 n/a Gas Distribution 112 2 (13 ) n/a Retail Gas Marketing 68 — n/a $ (3 ) Energy Marketing 146 34 n/a (1 ) All Other — 102 — (9 ) Adjustments/Eliminations — (139 ) (8 ) 162 Consolidated Total $ 1,068 $ — $ 292 $ 149 Nine Months Ended September 30, 2015 Electric Operations $ 2,008 $ 4 $ 728 n/a Gas Distribution 609 2 88 n/a Retail Gas Marketing 344 — n/a $ 18 Energy Marketing 461 101 n/a 8 All Other 5 309 237 188 Adjustments/Eliminations (4 ) (416 ) 42 434 Consolidated Total $ 3,423 $ — $ 1,095 $ 648 Three Months Ended September 30, 2014 Electric Operations $ 739 $ 1 $ 275 n/a Gas Distribution 127 — (6 ) n/a Retail Gas Marketing 68 — n/a $ (3 ) Energy Marketing 182 47 n/a (2 ) All Other 9 103 7 (5 ) Adjustments/Eliminations (4 ) (151 ) (7 ) 154 Consolidated Total $ 1,121 $ — $ 269 $ 144 Nine Months Ended September 30, 2014 Electric Operations $ 2,027 $ 5 $ 616 n/a Gas Distribution 728 — 98 n/a Retail Gas Marketing 367 — n/a $ 16 Energy Marketing 602 154 n/a 5 All Other 27 317 21 (3 ) Adjustments/Eliminations (15 ) (476 ) 37 415 Consolidated Total $ 3,736 $ — $ 772 $ 433 September 30, December 31, Segment Assets 2015 2014 Electric Operations $ 10,531 $ 10,182 Gas Distribution 2,498 2,487 Retail Gas Marketing 107 140 Energy Marketing 102 150 All Other 998 1,474 Adjustments/Eliminations 2,270 2,419 Consolidated Total $ 16,506 $ 16,852
SCEG
Segment Reporting Information [Line Items]
Segment Reporting Disclosure [Text Block]	SEGMENT OF BUSINESS INFORMATION Consolidated SCE&G’s reportable segments are listed in the following table. Consolidated SCE&G uses operating income to measure profitability for its regulated operations. Therefore, earnings available to common shareholder are not allocated to the Electric Operations and Gas Distribution segments. Intersegment revenues were not significant. Millions of dollars External Revenue Operating Income Earnings Available to Common Shareholder Three Months Ended September 30, 2015 Electric Operations $ 743 $ 313 n/a Gas Distribution 63 (6 ) n/a Adjustments/Eliminations — — $ 164 Consolidated Total $ 806 $ 307 $ 164 Nine Months Ended September 30, 2015 Electric Operations $ 2,013 $ 728 n/a Gas Distribution 275 35 n/a Adjustments/Eliminations — — $ 394 Consolidated Total $ 2,288 $ 763 $ 394 Three Months Ended September 30, 2014 Electric Operations $ 740 $ 274 n/a Gas Distribution 72 (2 ) n/a Adjustments/Eliminations — — $ 154 Consolidated Total $ 812 $ 272 $ 154 Nine Months Ended September 30, 2014 Electric Operations $ 2,032 $ 616 n/a Gas Distribution 337 40 n/a Adjustments/Eliminations — — $ 374 Consolidated Total $ 2,369 $ 656 $ 374 Segment Assets September 30, 2015 December 31, 2014 Electric Operations $ 10,531 $ 10,182 Gas Distribution 749 721 Adjustments/Eliminations 3,032 3,204 Consolidated Total $ 14,312 $ 14,107

AFFILIATED TRANSACTIONS - SCEG

AFFILIATED TRANSACTIONS - SCEG	9 Months Ended
	Sep. 30, 2015
SCEG
Related Party Transactions Disclosure [Text Block]	AFFILIATED TRANSACTIONS CGT transports natural gas to SCE&G to serve retail gas customers and certain electric generation requirements. Prior to January 31, 2015, CGT was a wholly-owned subsidiary of SCANA, and SCE&G's transactions with CGT prior to January 31, 2015 were affiliated transactions. SCE&G's affiliated purchases from CGT totaled approximately $6.9 million for the three months ended September 30, 2014, and $3.4 million and $21.6 million for the nine months ended September 30, 2015 and 2014, respectively. SCE&G's affiliated payables to CGT for transportation services were $3.3 million at December 31, 2014, and SCE&G's affiliated 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 $34.0 million and $46.8 million for the three months ended September 30, 2015 and 2014, respectively, and $101.4 million and $154.1 million for the nine months ended September 30, 2015 and 2014, respectively. SCE&G’s payables to SEMI for such purchases were $9.6 million at September 30, 2015 and $12.6 million at December 31, 2014. 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 $66.3 million and $82.4 million for the three months ended September 30, 2015 and 2014, respectively, and $186.0 million and $191.9 million for the nine months ended September 30, 2015 and 2014, respectively. SCE&G’s total sales to this affiliate were $65.9 million and $82.0 million for the three months ended September 30, 2015 and 2014, respectively, and $185.1 million and $190.9 million for the nine months ended September 30, 2015 and 2014, respectively. SCE&G’s receivable from this affiliate was $21.6 million at September 30, 2015 and $27.8 million at December 31, 2014. SCE&G’s payable to this affiliate was $21.8 million at September 30, 2015 and $27.9 million at December 31, 2014. SCANA Services 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 were $80.8 million and $65.0 million for the three months ended September 30, 2015 and 2014, respectively, and $226.0 million and $211.4 million for the nine months ended September 30, 2015 and 2014, respectively. Consolidated SCE&G's payables to SCANA Services for these services were $37.2 million at September 30, 2015 and $47.3 million at December 31, 2014. Money pool borrowings from an affiliate are described in Note 4.

Dispositions (Notes)

Dispositions (Notes)	9 Months Ended
	Sep. 30, 2015
Disposal groups [Abstract]
Disposal Group, Held for Sale [Text Block]	DISPOSITIONS In December 2014, SCANA entered into definitive agreements to sell CGT and SCI. CGT is an interstate natural gas pipeline regulated by FERC that transports natural gas in South Carolina and southeastern Georgia, and it was sold to Dominion Resources, Inc. SCI provides fiber optic communications and other services and builds, manages and leases communications towers in several southeastern states, and it was sold to a subsidiary of Spirit Communications. These sales closed in the first quarter of 2015 and resulted in recognition of pre-tax gains totaling approximately $342 million . As further described in Note 1, the pre-tax gain from the sale of CGT is included within Operating Income and the pre-tax gain from the sale of SCI is included within Other Income (Expense) on the condensed consolidated income statement. CGT and SCI operate principally in wholesale markets, whereas the Company's primary focus is the delivery of energy-related products and services to retail markets. In addition, neither CGT nor SCI met accounting criteria for disclosure as a reportable segment and were included within All Other in Note 10. The sales of CGT and SCI did not represent a strategic shift that will have a major effect on SCANA's operations; therefore, these sales do not meet the criteria for classification as discontinued operations. The carrying values of the 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

SUMMARY OF SIGNIFICANT ACCOUN22

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	9 Months Ended
	Sep. 30, 2015
Significant Accounting Policies
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles 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.
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. In the third quarter of 2015, in connection with the adoption of a customary depreciation study and related analysis, SCE&G determined that these three units would not likely be retired by 2020 (see Note 2), 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 September 30, 2015.
Asset Management and Supply Service Agreements	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 50% and 48% of PSNC Energy’s natural gas inventory at September 30, 2015 and December 31, 2014, respectively, with a carrying value of $19.1 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 of which 75% are credited to rate payers. No fees are received under supply service agreements. The agreements, which expired on March 31, 2015, were replaced with similar agreements scheduled to expire March 31, 2017.
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 10) 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).
SCEG
Significant Accounting Policies
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles 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.
Consolidation, Variable Interest Entity, Policy [Policy Text Block]	Variable Interest Entities 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 condensed consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. Accordingly, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s condensed consolidated financial statements. GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $489 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 allowances. See also Note 4.
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. In the third quarter of 2015, in connection with the adoption of a customary depreciation study and related analysis, SCE&G determined that these three units would not likely be retired by 2020 (see Note 2), 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 September 30, 2015.

RATE AND OTHER REGULATORY MAT23

RATE AND OTHER REGULATORY MATTERS (Tables)	9 Months Ended
	Sep. 30, 2015
Regulatory Assets
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 Action Amount 2015 2.6 % Increase $ 64.5 million 2014 2.8 % Increase $ 66.2 million 2013 2.9 % Increase $ 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]	. Millions of dollars September 30, December 31, Regulatory Assets: Accumulated deferred income taxes $ 284 $ 284 Under-collections - electric fuel adjustment clause — 20 Environmental remediation costs 39 40 AROs and related funding 376 366 Franchise agreements 23 26 Deferred employee benefit plan costs 328 350 Planned major maintenance — 2 Deferred losses on interest rate derivatives 538 453 Deferred pollution control costs 35 36 Unrecovered plant 128 137 DSM Programs 59 56 Carrying costs on deferred tax assets related to nuclear construction 15 9 Pipeline integrity management costs 16 9 Other 43 35 Total Regulatory Assets $ 1,884 $ 1,823
Schedule of Regulatory Liabilities [Table Text Block]	Regulatory Liabilities: Accumulated deferred income taxes $ 22 $ 22 Asset removal costs 729 703 Storm damage reserve 6 6 Deferred gains on interest rate derivatives 87 82 Planned major maintenance 12 — Other 3 1 Total Regulatory Liabilities $ 859 $ 814
SCEG
Regulatory Assets
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 Action Amount 2015 2.6 % Increase $ 64.5 million 2014 2.8 % Increase $ 66.2 million 2013 2.9 % Increase $ 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]	Millions of dollars September 30, December 31, Regulatory Assets: Accumulated deferred income taxes $ 278 $ 278 Under collections – electric fuel adjustment clause — 20 Environmental remediation costs 35 36 AROs and related funding 356 347 Franchise agreements 23 26 Deferred employee benefit plan costs 296 310 Planned major maintenance — 2 Deferred losses on interest rate derivatives 538 453 Deferred pollution control costs 35 36 Unrecovered plant 128 137 DSM Programs 59 56 Carrying costs on deferred tax assets related to nuclear construction 15 9 Other 45 35 Total Regulatory Assets $ 1,808 $ 1,745
Schedule of Regulatory Liabilities [Table Text Block]	Regulatory Liabilities: Accumulated deferred income taxes $ 16 $ 17 Asset removal costs 520 505 Storm damage reserve 6 6 Deferred gains on interest rate derivatives 87 82 Planned major maintenance 12 — Total Regulatory Liabilities $ 641 $ 610

COMMON EQUITY (Tables)

COMMON EQUITY (Tables)	9 Months Ended
	Sep. 30, 2015
Schedule of Capitalization, Equity [Line Items]
Schedule of Stockholders Equity [Table Text Block]	Common Stock Accumulated Other Comprehensive Income (Loss) Millions Shares Outstanding Amount Treasury Shares Retained Earnings Gains(Losses) on Cash Flow Hedges Deferred Employee Benefit Plans Total AOCI Total Common Equity Balance as of January 1, 2015 143 $ 2,388 $ (10 ) $ 2,684 $ (63 ) $ (12 ) $ (75 ) $ 4,987 Net Income 648 648 Other Comprehensive Income (Loss): Losses during the period (8 ) (3 ) (11 ) (11 ) Reclassified from AOCI 16 — 16 16 Total Comprehensive Income (Loss) 648 8 (3 ) 5 653 Issuance of Common Stock — 14 (1 ) 13 Dividends Declared (234 ) (234 ) Balance as of September 30, 2015 143 $ 2,402 $ (11 ) $ 3,098 $ (55 ) $ (15 ) $ (70 ) $ 5,419 Balance as of January 1, 2014 141 $ 2,289 $ (9 ) $ 2,444 $ (52 ) $ (8 ) $ (60 ) $ 4,664 Net Income 433 433 Other Comprehensive Income: Losses during the period (3 ) — (3 ) (3 ) Reclassified from AOCI 1 1 2 2 Total Comprehensive Income 433 (2 ) 1 (1 ) 432 Issuance of Common Stock 1 76 (1 ) 75 Dividends Declared (223 ) (223 ) Balance as of September 30, 2014 142 $ 2,365 $ (10 ) $ 2,654 $ (54 ) $ (7 ) $ (61 ) $ 4,948
SCEG
Schedule of Capitalization, Equity [Line Items]
Schedule of Stockholders Equity [Table Text Block]	EQUITY Changes in common equity during the nine months ended September 30, 2015 and 2014 were as follows: Common Stock Retained Accumulated Other Comprehensive Noncontrolling Total Millions Shares Amount Earnings Income (Loss) Interest Equity Balance at January 1, 2015 40 $ 2,560 $ 2,077 $ (3 ) $ 123 $ 4,757 Earnings available to common shareholder 394 11 405 Deferred cost of employee benefit plans — — Total Comprehensive Income 394 — 11 405 Capital contributions from parent 196 196 Cash dividend declared (205 ) (5 ) (210 ) Balance at September 30, 2015 40 $ 2,756 $ 2,266 $ (3 ) $ 129 $ 5,148 Balance at January 1, 2014 40 $ 2,479 $ 1,896 $ (3 ) $ 117 $ 4,489 Earnings available to common shareholder 374 9 383 Deferred cost of employee benefit plans — — Total Comprehensive Income 374 — 9 383 Capital contributions from parent 82 82 Cash dividend declared (192 ) (5 ) (197 ) Balance at September 30, 2014 40 $ 2,561 $ 2,078 $ (3 ) $ 121 $ 4,757

LONG-TERM AND SHORT-TERM DEBT (

LONG-TERM AND SHORT-TERM DEBT (Tables)	9 Months Ended
	Sep. 30, 2015
Short-term Debt [Line Items]
Schedule of Line of Credit Facilities [Table Text Block]	SCANA, SCE&G (including Fuel Company) and PSNC Energy had available the following committed LOC, and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations: SCANA SCE&G PSNC Energy Millions of dollars September 30, December 31, September 30, December 31, September 30, December 31, Lines of credit: Total committed long-term $ 300 $ 300 $ 1,400 $ 1,400 $ 100 $ 100 Outstanding commercial paper ( 270 or fewer days) $ 14 $ 179 $ 234 $ 709 $ 16 $ 30 Weighted average interest rate 0.66 % 0.54 % 0.44 % 0.52 % 0.45 % 0.65 % Letters of credit supported by LOC $ 3 $ 3 $ 0.3 $ 0.3 — — Available $ 283 $ 118 $ 1,166 $ 691 $ 84 $ 70
SCEG
Short-term Debt [Line Items]
Schedule of Line of Credit Facilities [Table Text Block]	SCE&G (including Fuel Company) had available the following committed LOC, and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations: Millions of dollars September 30, December 31, Lines of credit: Total committed long-term $ 1,400 $ 1,400 Outstanding commercial paper (270 or fewer days) $ 234 $ 709 Weighted average interest rate 0.44 % 0.52 % Letters of credit supported by LOC $ 0.3 $ 0.3 Available $ 1,166 $ 691

DERIVATIVE FINANCIAL INSTRUME26

DERIVATIVE FINANCIAL INSTRUMENTS (Tables)	9 Months Ended
	Sep. 30, 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 September 30, 2015 Commodity contracts 9,270,000 11,788,000 4,335,500 25,393,500 Energy management contracts (a) — — 32,211,282 32,211,282 Total (a) 9,270,000 11,788,000 36,546,782 57,604,782 As of December 31, 2014 Commodity contracts 6,840,000 7,951,000 3,446,720 18,237,720 Energy management contracts (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 1,246,230 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 interest rate and energy-related derivatives was as follows: Fair Values of Derivative Instruments Millions of dollars Balance Sheet Location Asset Liability As of September 30, 2015 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 4 Other deferred credits and other liabilities 31 Commodity contracts Other current assets 1 Derivative financial instruments 6 Total $ 42 Not designated as hedging instruments Interest rate contracts Other deferred debits and other assets $ 6 — Derivative financial instruments — $ 107 Other deferred credits and other liabilities — 60 Energy management contracts Other current assets 10 2 Derivative financial instruments — 8 Other deferred debits and other assets 5 — Other deferred credits and other liabilities — 4 Total $ 21 $ 181 Millions of dollars Balance Sheet Location Asset Liability 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 Derivative financial instruments — 10 Other deferred debits and other assets 5 — 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]	Derivatives in Cash Flow Hedging Relationships Loss Deferred in Regulatory Accounts Loss Reclassified from Deferred Accounts into Income (Effective Portion) (Effective Portion) Millions of dollars 2015 2014 Location 2015 2014 Three Months Ended September 30, Interest rate contracts $ (3 ) $ (1 ) Interest expense $ (1 ) $ (1 ) Nine Months Ended September 30, Interest rate contracts $ (3 ) $ (5 ) Interest expense $ (2 ) $ (2 ) Gain (Loss) Recognized in OCI, net of tax Gain (Loss) Reclassified from AOCI into Income, net of tax (Effective Portion) (Effective Portion) Millions of dollars 2015 2014 Location 2015 2014 Three Months Ended September 30, Interest rate contracts $ (3 ) — Interest expense $ (2 ) $ (2 ) Commodity contracts (4 ) $ (2 ) Gas purchased for resale (1 ) — Total $ (7 ) $ (2 ) $ (3 ) $ (2 ) Nine Months Ended September 30, Interest rate contracts $ (3 ) $ (4 ) Interest expense $ (6 ) $ (5 ) Commodity contracts (5 ) 1 Gas purchased for resale (10 ) 4 Total $ (8 ) $ (3 ) $ (16 ) $ (1 )
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 Loss Deferred in Regulatory Accounts Gain Reclassified from Deferred Accounts into Income Millions of dollars 2015 2014 Location 2015 2014 Three Months Ended September 30, Interest rate contracts $ (116 ) $ (35 ) Other income — $ 5 Nine Months Ended September 30, Interest rate contracts $ (79 ) $ (220 ) Other income $ 5 $ 60
Offseting Assets [Table Text Block]	Information related to the Company's offsetting of derivative assets follows: Gross Amounts of Recognized 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 Financial Instruments Cash Collateral Received As of September 30, 2015 Interest rate contracts $ 6 — $ 6 $ (3 ) — $ 3 Energy management contracts 15 — 15 — — 15 Total $ 21 — $ 21 $ (3 ) — $ 18 Balance sheet location Other current assets $ 10 Other deferred debits and other assets 11 Total $ 21 As of December 31, 2014 Commodity contracts $ 1 — $ 1 — — $ 1 Energy management contracts 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]	Information related to the Company's offsetting of derivative liabilities follows: Gross Amounts of Recognized 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 Financial Instruments Cash Collateral Posted As of September 30, 2015 Interest rate contracts $ 202 — $ 202 $ (3 ) $ (135 ) $ 64 Commodity contracts 7 — 7 — (6 ) 1 Energy management contracts 14 — 14 — (7 ) 7 Total $ 223 — $ 223 $ (3 ) $ (148 ) $ 72 Balance sheet location Other current assets $ 3 Derivative financial instruments 125 Other deferred credits and other liabilities 95 Total $ 223 As of December 31, 2014 Interest rate contracts $ 257 — $ 257 — $ (131 ) $ 126 Commodity contracts 12 — 12 — (10 ) 2 Energy management contracts 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
SCEG
Derivative [Line Items]
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]	The fair value of interest rate derivatives was as follows: Fair Values of Derivative Instruments Fair Value Millions of dollars Balance Sheet Location Asset Liability As of September 30, 2015 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 1 Other deferred credits and other liabilities 10 Total $ 11 Not designated as hedging instruments Interest rate contracts Derivative financial instruments — $ 107 Other deferred debits and other assets $ 6 Other deferred credits and other liabilities — 60 Total $ 6 $ 167 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 condensed consolidated statement of income is as follows: Derivatives in Cash Flow Hedging Relationships Loss Deferred in Regulatory Accounts Loss Reclassified from Deferred Accounts into Income (Effective Portion) (Effective Portion) Millions of dollars 2015 2014 Location 2015 2014 Three Months Ended September 30, Interest rate contracts $ (3 ) $ (1 ) Interest expense $ (1 ) $ (1 ) Nine Months Ended September 30, Interest rate contracts $ (3 ) $ (5 ) Interest expense $ (2 ) $ (2 )
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 Loss Deferred in Regulatory Accounts Gain Reclassified from Deferred Accounts into Income Millions of dollars 2015 2014 Location 2015 2014 Three Months Ended September 30, Interest rate contracts $ (116 ) $ (35 ) Other income — $ 5 Nine Months Ended September 30, Interest rate contracts $ (79 ) $ (220 ) Other income $ 5 $ 60
Offseting Assets [Table Text Block]	Information related to Consolidated SCE&G's derivative assets follows: Gross Amounts of Recognized 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 Financial Instruments Cash Collateral Received As of September 30, 2015 Interest rate contracts $ 6 — $ 6 $ (3 ) — $ 3 Balance Sheet Location Other deferred debits and other assets $ 6
Offsetting Liabilities [Table Text Block]	Information related to Consolidated SCE&G's derivative liabilities follows: Gross Amounts of Recognized 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 Financial Instruments Cash Collateral Posted As of September 30, 2015 Interest rate contracts $ 178 — $ 178 $ (3 ) $ (109 ) $ 66 Balance Sheet Location Derivative financial instruments $ 108 Other deferred credits and other liabilities 70 Total $ 178 As of December 31, 2014 Interest rate contracts $ 233 — $ 233 — $ (107 ) $ 126 Balance Sheet Location Derivative financial instruments $ 208 Other deferred credits and other liabilities 25 Total $ 233

FAIR VALUE MEASUREMENTS, INCL27

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Tables)	9 Months Ended
	Sep. 30, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	Fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows: As of September 30, 2015 As of December 31, 2014 Millions of dollars Level 1 Level 2 Level 1 Level 2 Assets: Available for sale securities $ 13 — $ 13 — Interest rate contracts — $ 6 — — Commodity contracts — — 1 — Energy management contracts — 15 — $ 20 Liabilities: Interest rate contracts — 202 — 257 Commodity contracts 1 6 1 11 Energy management contracts 2 15 5 18
Fair Value, by Balance Sheet Grouping [Table Text Block]	Financial instruments for which the carrying amount may not equal estimated fair value were as follows: September 30, 2015 December 31, 2014 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Long-term debt $ 6,034.3 $ 6,623.3 $ 5,697.2 $ 6,592.1
SCEG
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	Fair value Level 2 measurements were as follows: Millions of dollars September 30, 2015 December 31, 2014 Assets - Interest rate contracts $ 6 — Liabilities - Interest rate contracts 178 $ 233
Fair Value, by Balance Sheet Grouping [Table Text Block]	Financial instruments for which the carrying amount may not equal estimated fair value were as follows: September 30, 2015 December 31, 2014 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Long-term debt $ 4,801.0 $ 5,277.6 $ 4,308.6 $ 5,070.9

EMPLOYEE BENEFIT PLANS (Tables)

EMPLOYEE BENEFIT PLANS (Tables)	9 Months Ended
	Sep. 30, 2015
Pension and Other Postretirement Benefit Plans
Schedule of Net Benefit Costs [Table Text Block]	Pension Benefits Other Postretirement Benefits Millions of dollars 2015 2014 2015 2014 Three months ended September 30, Service cost $ 6.6 $ 5.0 $ 1.2 $ 0.9 Interest cost 9.6 9.9 2.8 2.8 Expected return on assets (15.5 ) (16.4 ) — — Prior service cost amortization 1.0 1.1 0.1 0.1 Amortization of actuarial losses (gains) 3.2 0.9 0.4 (0.2 ) Net periodic benefit cost $ 4.9 $ 0.5 $ 4.5 $ 3.6 Nine months ended September 30, Service cost $ 18.1 $ 15.0 $ 4.0 $ 3.4 Interest cost 28.7 30.3 8.6 9.0 Expected return on assets (46.5 ) (50.0 ) — — Prior service cost amortization 3.0 3.1 0.3 0.3 Amortization of actuarial losses 10.2 3.5 1.5 — Net periodic benefit cost $ 13.5 $ 1.9 $ 14.4 $ 12.7
SCEG
Pension and Other Postretirement Benefit Plans
Schedule of Net Benefit Costs [Table Text Block]	Pension Benefits Other Postretirement Benefits Millions of dollars 2015 2014 2015 2014 Three months ended September 30, Service cost $ 5.3 $ 4.0 $ 1.0 $ 0.7 Interest cost 8.1 8.4 2.2 2.3 Expected return on assets (13.0 ) (13.9 ) — — Prior service cost amortization 0.8 0.9 0.1 — Amortization of actuarial losses (gains) 2.7 0.8 0.3 (0.2 ) Net periodic benefit cost $ 3.9 $ 0.2 $ 3.6 $ 2.8 Nine months ended September 30, Service cost $ 14.5 $ 12.0 $ 3.2 $ 2.7 Interest cost 24.1 25.6 6.8 7.1 Expected return on assets (39.1 ) (42.2 ) — — Prior service cost amortization 2.5 2.6 0.2 0.2 Amortization of actuarial losses 8.6 3.0 1.2 — Net periodic benefit cost $ 10.6 $ 1.0 $ 11.4 $ 10.0

COMMITMENTS AND CONTINGENCIES A

COMMITMENTS AND CONTINGENCIES Asset Retirement Obligation (Tables)	9 Months Ended
	Sep. 30, 2015
Change in Asset Retirement Obligation [Line Items]
Change in Asset Retirement Obligation [Table Text Block]	A reconciliation of the beginning and ending carrying amount of asset retirement obligations is as follows: Millions of dollars September 30, 2015 December 31, 2014 Beginning balance $ 563 $ 576 Liabilities incurred — 3 Liabilities settled (15 ) (6 ) Accretion expense 20 26 Revisions in estimated cash flows (79 ) (36 ) Ending balance $ 489 $ 563
SCEG
Change in Asset Retirement Obligation [Line Items]
Schedule of Change in Asset Retirement Obligation [Table Text Block]	A reconciliation of the beginning and ending carrying amount of asset retirement obligations is as follows: Millions of dollars September 30, 2015 December 31, 2014 Beginning balance $ 536 $ 547 Liabilities incurred — 3 Liabilities settled (15 ) (6 ) Accretion expense 18 25 Revisions in estimated cash flows (79 ) (33 ) Ending balance $ 460 $ 536

SEGMENT OF BUSINESS INFORMATI30

SEGMENT OF BUSINESS INFORMATION (Tables)	9 Months Ended
	Sep. 30, 2015
Segment Reporting Information [Line Items]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	Millions of dollars External Revenue Intersegment Revenue Operating Income Net Income Three Months Ended September 30, 2015 Electric Operations $ 742 $ 1 $ 313 n/a Gas Distribution 112 2 (13 ) n/a Retail Gas Marketing 68 — n/a $ (3 ) Energy Marketing 146 34 n/a (1 ) All Other — 102 — (9 ) Adjustments/Eliminations — (139 ) (8 ) 162 Consolidated Total $ 1,068 $ — $ 292 $ 149 Nine Months Ended September 30, 2015 Electric Operations $ 2,008 $ 4 $ 728 n/a Gas Distribution 609 2 88 n/a Retail Gas Marketing 344 — n/a $ 18 Energy Marketing 461 101 n/a 8 All Other 5 309 237 188 Adjustments/Eliminations (4 ) (416 ) 42 434 Consolidated Total $ 3,423 $ — $ 1,095 $ 648 Three Months Ended September 30, 2014 Electric Operations $ 739 $ 1 $ 275 n/a Gas Distribution 127 — (6 ) n/a Retail Gas Marketing 68 — n/a $ (3 ) Energy Marketing 182 47 n/a (2 ) All Other 9 103 7 (5 ) Adjustments/Eliminations (4 ) (151 ) (7 ) 154 Consolidated Total $ 1,121 $ — $ 269 $ 144 Nine Months Ended September 30, 2014 Electric Operations $ 2,027 $ 5 $ 616 n/a Gas Distribution 728 — 98 n/a Retail Gas Marketing 367 — n/a $ 16 Energy Marketing 602 154 n/a 5 All Other 27 317 21 (3 ) Adjustments/Eliminations (15 ) (476 ) 37 415 Consolidated Total $ 3,736 $ — $ 772 $ 433 September 30, December 31, Segment Assets 2015 2014 Electric Operations $ 10,531 $ 10,182 Gas Distribution 2,498 2,487 Retail Gas Marketing 107 140 Energy Marketing 102 150 All Other 998 1,474 Adjustments/Eliminations 2,270 2,419 Consolidated Total $ 16,506 $ 16,852
SCEG
Segment Reporting Information [Line Items]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	. Millions of dollars External Revenue Operating Income Earnings Available to Common Shareholder Three Months Ended September 30, 2015 Electric Operations $ 743 $ 313 n/a Gas Distribution 63 (6 ) n/a Adjustments/Eliminations — — $ 164 Consolidated Total $ 806 $ 307 $ 164 Nine Months Ended September 30, 2015 Electric Operations $ 2,013 $ 728 n/a Gas Distribution 275 35 n/a Adjustments/Eliminations — — $ 394 Consolidated Total $ 2,288 $ 763 $ 394 Three Months Ended September 30, 2014 Electric Operations $ 740 $ 274 n/a Gas Distribution 72 (2 ) n/a Adjustments/Eliminations — — $ 154 Consolidated Total $ 812 $ 272 $ 154 Nine Months Ended September 30, 2014 Electric Operations $ 2,032 $ 616 n/a Gas Distribution 337 40 n/a Adjustments/Eliminations — — $ 374 Consolidated Total $ 2,369 $ 656 $ 374 Segment Assets September 30, 2015 December 31, 2014 Electric Operations $ 10,531 $ 10,182 Gas Distribution 749 721 Adjustments/Eliminations 3,032 3,204 Consolidated Total $ 14,312 $ 14,107

Dispositions (Tables)

Dispositions (Tables)	9 Months Ended
	Sep. 30, 2015
Disposal groups [Abstract]
Schedule of Disposal Group, Held for Sale [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

SUMMARY OF SIGNIFICANT ACCOUN32

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) $ in Millions	9 Months Ended
	Sep. 30, 2015USD ($)MW	Dec. 31, 2014USD ($)
Significant Accounting Policies
Property, Plant and Equipment, Net	$ 281	$ 284
SCEG
Significant Accounting Policies
Property, Plant and Equipment, Net	$ 67	$ 67
Genco
Significant Accounting Policies
Power Generation Capacity Megawatts | MW	605
Property, Plant and Equipment, Net	$ 489
PSNC Energy [Member]
Significant Accounting Policies
Percentage of natural gas inventory held by counterparties under asset management and supply service agreements (as a percent)	50.00%	48.00%
Natural gas inventory, carrying amount	$ 19.1	$ 26.1
PercentOfStorageFeesCreditedToRatePayers	75.00%

RATE AND OTHER REGULATORY MAT33

RATE AND OTHER REGULATORY MATTERS (Details)	3 Months Ended			6 Months Ended	9 Months Ended		12 Months Ended
	Sep. 30, 2015USD ($)MW	Sep. 30, 2014USD ($)	Mar. 31, 2014	Jun. 30, 2015	Sep. 30, 2015USD ($)MW$ / shares	Sep. 30, 2014USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Sep. 30, 2013USD ($)
Rate Matters [Line Items]
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, Effect Of Lower Depreciation Rates For YTD September 2015, Dollars					$ 22,000,000
Depreciation Study 2015, Effect Of Lower Depreciation Rates for YTD September 2015, Per Share | $ / shares					$ 0.09
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	$ 4,500,000				$ 4,500,000
Carrying cost recovery					(9,000,000)	$ (7,000,000)
Regulatory Assets, Noncurrent	1,884,000,000				$ 1,884,000,000		$ 1,823,000,000
Public Utilities Base Fuel under Collected Balance Recovery Period					12
Amortization Period For Carrying Cost On Accumlated Deferred Income Tax Assets Associated With New Units					10
SCEG
Rate Matters [Line Items]
Amounts Recovered Through Electric Rates to offset Nuclear Related Outage Costs					$ 17,200,000
Fuel Costs					10,300,000
Undercollected balance fuel	$ 46,000,000				$ 46,000,000
Capacity of renewable energy facilities by 2020 | MW	85				85
Capacity of renewable energy facilities by 2016 | MW	30				30
Depreciation Study 2015, Effect Of Lower Depreciation Rates Annually, Dollars					$ 29,000,000
Depreciation Study 2015, Effect Of Lower Depreciation Rates for YTD September 2015, Per Share | $ / shares					$ 22,000,000
Depreciation Study 2015, Undercollected Fuel Amount Offset by Lower Depreciation Rates, Dollars					$ 14,500,000
Depreciation Study 2015, Increase in Net Income	$ 4,500,000				4,500,000
Carrying costs on deferred income tax assets	2,400,000	$ 1,600,000			6,500,000	4,100,000
Carrying cost recovery					(9,000,000)	(7,000,000)
Regulatory Assets, Noncurrent	1,808,000,000				$ 1,808,000,000		1,745,000,000
Allowable return on common equity (as a percent)				11.00%	11.00%
Demand Side Management Program Costs, Noncurrent	32,000,000	$ 15,400,000			$ 32,000,000	$ 15,400,000			$ 16,900,000
Increase (decrease) in retail electric rate requested under the BLRA					$ 65,000,000		$ 66,000,000	$ 67,200,000
Public Utilities, Percent Increase (Decrease) in Retail Electric Rates					0.00%		0.00%	2.90%
Public Utilities, Percent Increase (Decrease) in Retail Natural Gas Rates							0.60%
Public Utilities changes in Retail Natural Gas Rates Approved under RSA							$ 2,600,000
Public Utilities, Rate Calculation Basis					12-month rolling average
Public Utilities Base Fuel under Collected Balance Recovery Period					12
Derivative, Gain on Derivative							17,800,000
Storm Damage Reserve Cost Applied							5,000,000
Demand side management recovery period					5
Amortization Period For Carrying Cost On Accumlated Deferred Income Tax Assets Associated With New Units					10
Pipeline Integrity Management Costs, Annual					$ 1,900,000
Amount Allowed to be Recovered through Electric Rates to Offset Incremental Storm Damage Costs					$ 100,000,000
PSNC Energy
Rate Matters [Line Items]
Public Utilities, Rate Calculation Basis			12
Pension costs, electric [Member] | SCEG
Rate Matters [Line Items]
Regulatory Noncurrent Asset Amortization Period					30 years
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority	63,000,000				$ 63,000,000
Pension costs, gas [Member] | SCEG
Rate Matters [Line Items]
Regulatory Noncurrent Asset Amortization Period								14 years
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority	14,000,000				14,000,000
Pension Costs [Member]
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	328,000,000				328,000,000		350,000,000
Pension Costs [Member] | SCEG
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	296,000,000				$ 296,000,000		310,000,000
Regulatory Noncurrent Asset Amortization Period					12 years			30 years
Other Regulatory Assets [Member]
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	43,000,000				$ 43,000,000		35,000,000
Regulatory Noncurrent Asset Amortization Period					30 years
Other Regulatory Assets [Member] | SCEG
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	45,000,000				$ 45,000,000		35,000,000
Deferred Pollution Control Costs
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	35,000,000				35,000,000		36,000,000
Deferred Pollution Control Costs | SCEG
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	35,000,000				35,000,000		36,000,000
Franchise agreement Costs
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	23,000,000				23,000,000		26,000,000
Franchise agreement Costs | SCEG
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	$ 23,000,000				23,000,000		$ 26,000,000
Planned major maintenance [Member] | SCEG
Rate Matters [Line Items]
Amounts Recovered through Electric Rates to offset Turbine Expense					18,400,000
Storm damage reserve [Member]
Rate Matters [Line Items]
Amount Allowed to be Recovered through Electric Rates to Offset Incremental Storm Damage Costs					$ 100,000,000

RATE AND OTHER REGULATORY MAT34

RATE AND OTHER REGULATORY MATTERS (Details 2) $ in Millions	3 Months Ended			6 Months Ended	9 Months Ended		12 Months Ended
	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)	Mar. 31, 2014USD ($)	Jun. 30, 2015	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Sep. 30, 2013USD ($)
Regulatory Assets
Regulatory Liabilities	$ 859				$ 859		$ 814
Public Utilities Base Fuel under Collected Balance Recovery Period					12
Regulatory Assets, Noncurrent	1,884				$ 1,884		$ 1,823
SCEG
Regulatory Assets
Public Utilities, Percent Increase (Decrease) in Retail Electric Rates					0.00%		0.00%	2.90%
Public Utilities Increase (Decrease) in Retail Electric Rates Approved under BLRA					$ 65		$ 66	$ 67.2
Public Utilities, Rate Calculation Basis					12-month rolling average
Fuel Costs					$ 10.3
Undercollected balance fuel	46				46
Public Utilities, Percent Increase (Decrease) in Retail Natural Gas Rates							0.60%
Regulatory Liabilities	641				641		$ 610
Annual Storm Damage Costs not offset by Amounts Recovered through Electric Rates					2.5
Carrying costs on deferred income tax assets	2.4	$ 1.6			6.5	$ 4.1
Derivative, Gain on Derivative							17.8
Storm Damage Reserve Cost Applied							5
Demand Side Management Program Costs, Noncurrent	32	$ 15.4			32	$ 15.4			$ 16.9
Amount Allowed to be Recovered through Electric Rates to Offset Incremental Storm Damage Costs					$ 100
Public Utilities Base Fuel under Collected Balance Recovery Period					12
Regulatory Assets, Noncurrent	1,808				$ 1,808		1,745
Demand side management recovery period					5
Storm Damage Reserve Applied To Offset Net Lost Margin Related To DSM			$ 5
Public Utilities changes in Retail Natural Gas Rates Approved under RSA							2.6
Amounts Recovered Through Electric Rates to offset Nuclear Related Outage Costs					$ 17.2
Public Utilities, Authorized Allowable Return on Common Equity, Percentage				11.00%	11.00%
PSNC Energy [Member]
Regulatory Assets
Public Utilities, Rate Calculation Basis			12
Other Regulatory Liability [Member]
Regulatory Assets
Regulatory Liabilities	3				$ 3		1
Asset Retirement Obligation Costs [Member]
Regulatory Assets
Regulatory Liabilities	729				729		703
Asset Retirement Obligation Costs [Member] | SCEG
Regulatory Assets
Regulatory Liabilities	520				520		505
Deferred Income Tax Charges [Member]
Regulatory Assets
Regulatory Liabilities	22				22		22
Deferred Income Tax Charges [Member] | SCEG
Regulatory Assets
Regulatory Liabilities	16				16		17
Storm damage reserve [Member]
Regulatory Assets
Regulatory Liabilities	6				6		6
Annual Storm Damage Costs not offset by Amounts Recovered through Electric Rates					2.5
Amount Allowed to be Recovered through Electric Rates to Offset Incremental Storm Damage Costs					100
Storm Damage Reserve Applied To Offset Net Lost Margin Related To DSM							5
Storm damage reserve [Member] | SCEG
Regulatory Assets
Regulatory Liabilities	6				6		6
Planned major maintenance [Member]
Regulatory Assets
Regulatory Liabilities	12				12		0
Planned major maintenance [Member] | SCEG
Regulatory Assets
Regulatory Liabilities	12				12		0
Amounts Recovered through Electric Rates to offset Turbine Expense					18.4
Deferred gains on interest rate derivatives [Member]
Regulatory Assets
Regulatory Liabilities	87				87		82
Deferred gains on interest rate derivatives [Member] | SCEG
Regulatory Assets
Regulatory Liabilities	87				$ 87		82
Pension costs, electric [Member] | SCEG
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period					30 years
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority	63				$ 63
Franchise agreement Costs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	23				23		26
Franchise agreement Costs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	23				23		26
Deferred Losses On Interest Rate Derivatives [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	538				538		453
Deferred Losses On Interest Rate Derivatives [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	538				538		453
Deferred Pollution Control Cost [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	35				35		36
Deferred Pollution Control Cost [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	35				35		36
Regulatory Clause Revenues, under-recovered [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	0				0		20
Regulatory Clause Revenues, under-recovered [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	0				0		20
Planned major maintenance [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	0				0		2
Planned major maintenance [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	0				$ 0		2
Asset Retirement Obligation Costs [Member]
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period					110 years
Regulatory Assets, Noncurrent	376				$ 376		366
Asset Retirement Obligation Costs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	356				356		347
unrecovered plant [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	128				128		137
unrecovered plant [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	128				128		137
Demand Side Management programs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	59				59		56
Demand Side Management programs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	59				59		56
Carrying cost on nuclear construction [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	15				15		9
Carrying cost on nuclear construction [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	15				15		9
Pipeline integerity management costs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	16				$ 16		9
Deferred Income Tax Charges [Member]
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period					85 years
Regulatory Assets, Noncurrent	284				$ 284		284
Deferred Income Tax Charges [Member] | SCEG
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period					85 years
Regulatory Assets, Noncurrent	278				$ 278		278
Environmental Restoration Costs [Member]
Regulatory Assets
MPG enviromental remediatio					24
Regulatory Assets, Noncurrent	39				$ 39		40
Environmental Restoration Costs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	35				35		36
Pension Costs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	328				$ 328		350
Pension Costs [Member] | SCEG
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period					12 years			30 years
Regulatory Assets, Noncurrent	296				$ 296		310
Pension costs, gas [Member] | SCEG
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period								14 years
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority	14				$ 14
Other Regulatory Assets [Member]
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period					30 years
Regulatory Assets, Noncurrent	43				$ 43		35
Other Regulatory Assets [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	$ 45				$ 45		$ 35

RATE AND OTHER REGULATORY MAT35

RATE AND OTHER REGULATORY MATTERS (Details 3) - USD ($) $ in Millions	3 Months Ended	6 Months Ended	9 Months Ended	12 Months Ended
	Mar. 31, 2014	Jun. 30, 2015	Sep. 30, 2015	Dec. 31, 2014	Dec. 31, 2013	Sep. 30, 2014	Sep. 30, 2013
Regulatory Liabilities [Line Items]
Regulatory Assets, Noncurrent			$ 1,884	$ 1,823
Regulatory Liabilities			859	$ 814
SCEG
Regulatory Liabilities [Line Items]
Public Utilities, Percent Increase (Decrease) in Retail Natural Gas Rates				0.60%
Storm Damage Reserve Applied To Offset Net Lost Margin Related To DSM	$ 5
Regulatory Assets, Noncurrent			1,808	$ 1,745
Public Utilities Increase (Decrease) in Retail Electric Rates Approved under BLRA			$ 65	66	$ 67.2
Public Utilities, Authorized Allowable Return on Common Equity, Percentage		11.00%	11.00%
Demand Side Management Program Costs, Noncurrent			$ 32			$ 15.4	$ 16.9
Regulatory Liabilities			641	610
Annual Storm Damage Costs not offset by Amounts Recovered through Electric Rates			2.5
Amount Allowed to be Recovered through Electric Rates to Offset Incremental Storm Damage Costs			100
Asset Retirement Obligation Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities			729	703
Asset Retirement Obligation Costs [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities			520	505
Storm damage reserve [Member]
Regulatory Liabilities [Line Items]
Storm Damage Reserve Applied To Offset Net Lost Margin Related To DSM				5
Regulatory Liabilities			6	6
Annual Storm Damage Costs not offset by Amounts Recovered through Electric Rates			2.5
Amount Allowed to be Recovered through Electric Rates to Offset Incremental Storm Damage Costs			100
Storm damage reserve [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities			6	6
Deferred gains on interest rate derivatives [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities			87	82
Deferred gains on interest rate derivatives [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities			87	82
Deferred Income Tax Charges [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities			22	22
Deferred Income Tax Charges [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities			16	17
Planned major maintenance [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities			12	0
Planned major maintenance [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities			$ 12	$ 0

COMMON EQUITY (Details)

COMMON EQUITY (Details) - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013
Schedule of Capitalization, Equity [Line Items]
Common Stock, Value, Outstanding	$ 2,391		$ 2,391		$ 2,378
Common Stock, Shares Authorized	200		200		200
COMMON EQUITY [Abstract]
Dividends declared			$ (234)	$ (223)
Stock Issued During Period, Shares, New Issues				1
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	$ 146	$ 145	653	$ 432
Proceeds from Issuance of Common Stock			14	75
Stock Issued During Period, Value, New Issues			13	76
Stock Repurchase Program, Authorized Amount	(1)	(1)	(1)	(1)
Treasury Stock, Value	$ (11)	$ (10)	$ (11)	$ (10)	$ (10)	$ (9)
Common Stock, Shares, Outstanding	142.9	142	142.9	142	142.7	141
Stockholders' Equity before Treasury Stock	$ 2,402	$ 2,365	$ 2,402	$ 2,365	$ 2,388	$ 2,289
Retained Earnings, Unappropriated	3,098	2,654	3,098	2,654	2,684	2,444
Accumulated Other Comprehensive Income (Loss), Net of Tax	(70)		(70)		(75)
AOCI before Tax, Attributable to Parent	55	54	55	54	63
Other Comprehensive Income (Loss), Net of Tax	(3)	1	5	(1)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, before Reclassification Adjustments, Net of Tax	1		(3)	(1)
Defined Benefit Plan, Accumulated Benefit Obligation	(15)	(7)	(15)	(7)
Defined Benefit Plan, Benefit Obligation	3	1	3	1	(12)	(8)
AOCI Tax, Attributable to Parent						52
Income Available to Common Shareholders	149	144	648	433
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	(4)	0	8	(2)
Common equity	5,419	4,948	5,419	4,948	4,987	4,664
AOCI Attributable to Parent [Member]
COMMON EQUITY [Abstract]
Accumulated Other Comprehensive Income (Loss), Net of Tax	70	61	70	61
AOCI before Tax, Attributable to Parent	(11)	(3)	(11)	(3)	$ (75)
AOCI Tax, Attributable to Parent						$ (60)
Reclassification out of Accumulated Other Comprehensive Income [Member]
COMMON EQUITY [Abstract]
AOCI before Tax, Attributable to Parent	$ (16)	$ (2)	$ (16)	$ (2)
SCEG
Schedule of Capitalization, Equity [Line Items]
Common Stock, Shares, Issued	40.3	40.3	40.3	40.3	40.3	40.3
Common Stock, Value, Outstanding	$ 2,756		$ 2,756		$ 2,560
Common Stock, Shares Authorized	50		50
COMMON EQUITY [Abstract]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ 167	$ 157	$ 405	$ 383
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax			0	0
Proceeds from Contribution from Parent, net of return of Proceeds			196	82
Dividends			(210)	(197)
Net Income (Loss) Attributable to Noncontrolling Interest	$ 3	3	11	9
Comprehensive Income (Loss), Net of Tax, Attributable to Parent			$ 405	383
Common Stock, Shares, Outstanding	40.3		40.3		40.3
Preferred Stock, Shares Authorized	20		20
Preferred Stock, Shares Outstanding	0		0
Preferred Stock, Value, Issued	$ 0		$ 0
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	5,148	4,757	5,148	4,757	$ 4,757	$ 4,489
Retained Earnings, Unappropriated	2,266		2,266		2,077
Accumulated Other Comprehensive Income (Loss), Net of Tax	(3)		$ (3)		(3)
Reclassifcations of deferred employee benefit costs			not significant
Common equity	5,019		$ 5,019		4,634
SCEG excluding VIEs [Member]
Schedule of Capitalization, Equity [Line Items]
Common Stock, Value, Outstanding	2,756	2,561	2,756	2,561	2,560	2,479
COMMON EQUITY [Abstract]
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax			0	0
Dividends			(205)	(192)
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	164	154	394	374
Retained Earnings, Unappropriated	2,266	2,078	2,266	2,078	2,077	1,896
Accumulated Other Comprehensive Income (Loss), Net of Tax	(3)	(3)	(3)	(3)	(3)	(3)
Income Available to Common Shareholders			394	374
Noncontrolling Interest [Member]
COMMON EQUITY [Abstract]
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders			(5)	(5)
Net Income (Loss) Attributable to Noncontrolling Interest			11	9
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	129	121	129	121	$ 123	$ 117
Interest Rate Contract
Schedule of Capitalization, Equity [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(2)	(2)	(6)	(5)
Commodity Contract
Schedule of Capitalization, Equity [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(1)	0	(10)	4
Accumulated Net Investment Gain (Loss) Attributable to Parent [Member] | Other Comprehensive Income (Loss) [Member]
COMMON EQUITY [Abstract]
AOCI before Tax, Attributable to Parent	8	3	8	3
Gain (Loss) on Derivative Instruments [Member] | Other Comprehensive Income Location [Domain]
COMMON EQUITY [Abstract]
AOCI before Tax, Attributable to Parent	(16)	(1)	(16)	(1)
Interest Expense [Member] | Cash Flow Hedging [Member] | Interest Rate Contract
Schedule of Capitalization, Equity [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	2	2	6	5
Gas Purchased for Resale [Member] [Member] | Cash Flow Hedging [Member] | Commodity Contract
Schedule of Capitalization, Equity [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 1	$ 0	$ 10	$ (4)

LONG-TERM AND SHORT-TERM DEBT37

LONG-TERM AND SHORT-TERM DEBT (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended		9 Months Ended
	Mar. 31, 2015	Jun. 30, 2015	Jun. 30, 2014	Sep. 30, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				$ 1,800
Commercial Paper Maximum Term				270
Number of other banks (in entities)				2
Long-term Debt, Current Maturities				$ 16	$ 166
Debt Instrument, Interest Rate Terms	0.077	.051
Junior Subordinated Notes	$ 150
Credit Suisse AG, Cayman Islands Branch (Member)
Debt Instrument [Line Items]
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				8.90%
Branch Banking Trust Company [Member]
Debt Instrument [Line Items]
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				6.30%
SCE&G (including Fuel Company)
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				$ 1,400	1,400
Commercial Paper				$ 234	$ 709
Debt, Weighted Average Interest Rate				0.44%	0.52%
Letters of Credit Outstanding, Amount				$ 0.3	$ 0.3
Line of Credit Facility, Remaining Borrowing Capacity				1,166	691
SCEG
Debt Instrument [Line Items]
Proceeds from Issuance of First Mortgage Bond		$ 500	$ 300
Line of Credit Facility, Maximum Borrowing Capacity				1,200
Long-term Debt, Current Maturities				10	10
Debt Instrument, Face Amount				$ 67.8
Debt Instrument, Interest Rate Terms		0.051	.045
SCEG | Branch Banking Trust Company [Member]
Debt Instrument [Line Items]
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				8.90%
PSNC Energy [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				$ 100	100
Commercial Paper				16	$ 30
Debt, Weighted Average Interest Rate					0.65%
Letters of Credit Outstanding, Amount				0	$ 0
Line of Credit Facility, Remaining Borrowing Capacity				84	$ 70
Fuel Company
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				$ 500

LONG-TERM AND SHORT-TERM DEBT38

LONG-TERM AND SHORT-TERM DEBT (Details 2) - USD ($) $ in Millions	3 Months Ended	6 Months Ended		9 Months Ended
	Mar. 31, 2015	Jun. 30, 2015	Jun. 30, 2014	Sep. 30, 2015	Dec. 31, 2014
Lines of credit:
Line of Credit Facility, Maximum Borrowing Capacity				$ 1,800
Commercial Paper Maximum Term				270
Number of other banks (in entities)				2
Debt Instrument, Interest Rate Terms	0.077	.051
Bank of America, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				10.70%
Morgan Stanly Bank, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				10.70%
BB&T Bank [Domain]
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				8.90%
CREDIT SUISSE (US) [Member]
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				8.90%
Credit Suisse AG, Cayman Islands Branch (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				10.70%
JPMorgan Chase Bank, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				8.90%
Mizuho Corporate Bank, Ltd (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				8.90%
TD Bank, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				8.90%
UBS Loan Finance LLC (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				8.90%
Deutsche Bank AG New York Branch [Member] [Member]
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				6.30%
Union Bank, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				6.30%
US Bank National Association (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				6.30%
Two other banks [Domain]
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				6.00%
JP Morgan Chase, Mizuho Corp, TD Bank, Credit Suisse AG ,Cayman Islands Branch and UBS Loan Finance [Member]
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				8.90%
SCEG
Debt Instrument [Line Items]
Proceeds from Issuance of First Mortgage Bond		$ 500	$ 300
Due to Affiliate, Current				$ 125	$ 180
Debt Instruments [Abstract]
Face value of Industrial Revenue Bonds issued, proceeds of which were availed as loan				67.8
Lines of credit:
Line of Credit Facility, Maximum Borrowing Capacity				1,200
3 year credit agreement				200
Related Party Transaction, Due from (to) Related Party, Current				$ 41.2	83
Due from Other Related Parties, Current					80
Debt Instrument, Interest Rate Terms		0.051	.045
SCEG | Bank of America, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				10.70%
SCEG | Morgan Stanly Bank, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				10.70%
SCEG | CREDIT SUISSE (US) [Member]
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				8.90%
SCEG | Credit Suisse AG, Cayman Islands Branch (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				10.70%
SCEG | JPMorgan Chase Bank, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				8.90%
SCEG | Mizuho Corporate Bank, Ltd (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				8.90%
SCEG | TD Bank, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				8.90%
SCEG | UBS Loan Finance LLC (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				8.90%
SCEG | Deutsche Bank AG New York Branch [Member] [Member]
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				6.30%
SCEG | Union Bank, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				6.30%
SCEG | US Bank National Association (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				6.30%
SCEG | Two other banks [Domain]
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				6.00%
Parent Company [Member]
Lines of credit:
Line of Credit Facility, Maximum Borrowing Capacity				$ 300	300
Commercial Paper				$ 14	$ 179
Commercial paper, weighted average interest rate (as a percent)				0.66%	0.54%
Letters of credit supported by LOC				$ (3)	$ (3)
Line of Credit Facility, Remaining Borrowing Capacity				283	118
SCE&G (including Fuel Company)
Lines of credit:
Line of Credit Facility, Maximum Borrowing Capacity				1,400	1,400
Commercial Paper				$ 234	$ 709
Commercial paper, weighted average interest rate (as a percent)				0.44%	0.52%
Letters of credit supported by LOC				$ (0.3)	$ (0.3)
Line of Credit Facility, Remaining Borrowing Capacity				1,166	691
3 year credit agreement		$ 200
Long-term Line of Credit		$ 1,400
Fuel Company
Lines of credit:
Line of Credit Facility, Maximum Borrowing Capacity				500
PSNC Energy
Lines of credit:
Line of Credit Facility, Maximum Borrowing Capacity				100	100
Commercial Paper				16	$ 30
Commercial paper, weighted average interest rate (as a percent)					0.65%
Letters of credit supported by LOC				0	$ 0
Line of Credit Facility, Remaining Borrowing Capacity				$ 84	$ 70

INCOME TAXES (Details)

INCOME TAXES (Details) $ in Millions	Sep. 30, 2015USD ($)
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	$ 18
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	14
Significant (Increase) Decrease in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Lower Bound	2
Significant (Increase) Decrease in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Upper Bound	8
SCEG
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	18
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	14
Significant (Increase) Decrease in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Lower Bound	2
Significant (Increase) Decrease in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Upper Bound	$ 8

DERIVATIVE FINANCIAL INSTRUME40

DERIVATIVE FINANCIAL INSTRUMENTS (Details) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2015USD ($)MMBTU	Dec. 31, 2014USD ($)MMBTU
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	57,604,782	55,733,059
Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	9,270,000	6,840,000
Retail Gas Marketing
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	11,788,000	7,951,000
Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	36,546,782	40,942,059
Commodity Contract
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	25,393,500	18,237,720
Commodity Contract | Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	9,270,000	6,840,000
Commodity Contract | Retail Gas Marketing
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	11,788,000	7,951,000
Commodity Contract | Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	4,335,500	3,446,720
Energy Related Derivative [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	32,211,282	37,495,339
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	32,211,282	37,495,339
Energy Related Derivative [Member] | Basis Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	1,246,230	933,893
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Interest Rate Derivatives [Abstract]
Derivative, Notional Amount	$ 1,200	$ 1,100
Cash Flow Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Interest Rate Derivatives [Abstract]
Derivative, Notional Amount	120	124.4
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Interest Rate Derivatives [Abstract]
Derivative, Notional Amount	1,200	1,100
SCEG | Cash Flow Hedging [Member] | Interest Rate Swap [Member]
Interest Rate Derivatives [Abstract]
Derivative, Notional Amount	$ 36.4	$ 36.4

DERIVATIVE FINANCIAL INSTRUME41

DERIVATIVE FINANCIAL INSTRUMENTS Fair Value on Balance Sheet (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Derivative [Line Items]
Derivative Liability	$ 223	$ 289
Derivative Asset	21	21
Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	11	5
Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability	95	50
Other Current Assets [Member]
Derivative [Line Items]
Derivative Liability	3	6
Derivative Asset	10	16
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Liability	202	257
Derivative Asset	6
Commodity Contract [Member]
Derivative [Line Items]
Derivative Liability	7	12
Derivative Asset		1
Other Energy Management Contract [Member]
Derivative [Line Items]
Derivative Liability	14	20
Derivative Asset	15	20
Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability	$ 42	45
Derivative Asset
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability	$ 4	5
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability	31	28
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability	$ 6	11
Derivative Asset
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Liability	$ 1	1
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability	181	244
Derivative Asset	21	21
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability	107	207
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	6
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability	60	17
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset		1
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability	8	10
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Liability	0
Derivative Asset	5	5
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability	4
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Liability	2	5
Derivative Asset	10	15
SCEG
Derivative [Line Items]
Derivative Liability	178	233
SCEG | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	6
SCEG | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability	70	25
SCEG | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Liability	178	233
Derivative Asset	6
SCEG | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability	11	9
SCEG | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability	1	1
SCEG | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability	10	8
SCEG | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability	167	224
Derivative Asset	6
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability	107	207
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	6
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability	$ 60	$ 17

DERIVATIVE FINANCIAL INSTRUME42

DERIVATIVE FINANCIAL INSTRUMENTS On Income Statement (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Derivative [Line Items]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	$ (7)	$ (2)	$ (8)	$ (3)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	$ (3)	$ (2)	$ (16)	$ (1)
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant	insignificant	insignificant	insignificant
Commodity Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 1	$ 0	$ 10	$ (4)
Commodity Contract | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	(4)	(2)	(5)	1
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	2	2	6	5
Interest Rate Contract [Member] | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	(3)	0	(3)	(4)
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	(116)	(35)	(79)	(220)
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	(3)	(1)	(3)	(5)
Other Nonoperating Income (Expense) [Member] | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	0	5	5	60
Gas Purchased for Resale [Member] [Member] | Commodity Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred			4
Gas Purchased for Resale [Member] [Member] | Commodity Contract | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(1)	0	(10)	4
Interest Expense [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred			6.5
Interest Expense [Member] | Interest Rate Contract [Member] | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(2)	(2)	(6)	(5)
Interest Expense [Member] | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred			0.6
Interest Expense [Member] | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred			2.3
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	$ (1)	$ (1)	$ (2)	$ (2)
SCEG
Derivative [Line Items]
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant	insignificant	insignificant	insignificant
SCEG | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	$ (116)	$ (35)	$ (79)	$ (220)
SCEG | Other Nonoperating Income (Expense) [Member] | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	0	5	5	60
SCEG | Interest Expense [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income Effective Portion, Net	(1)	(1)	(2)	(2)
SCEG | Interest Expense [Member] | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	$ (3)	$ (1)	(3)	$ (5)
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred			0.6
SCEG | Interest Expense [Member] | Interest Rate Contract [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred			$ 2.3

DERIVATIVE FINANCIAL INSTRUME43

DERIVATIVE FINANCIAL INSTRUMENTS Derivative Financial Instruments (Credit Risk) (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	$ 148.4	$ 152.4
Additional Collateral, Aggregate Fair Value	69.1	129.8
Derivative, Net Liability Position, Aggregate Fair Value	217.5	282.2
Cash collateral to request from interest rate derivative counterparty	2.8
LetterofCreditAvailableCommodityDerivatives,assetposition	3	9.2
Commodity Derivative, net asset position	15	20
Interest Rate Derivative, net asset position	2.8
SCEG
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	108.9	107.1
Additional Collateral, Aggregate Fair Value	65.8	125.9
Derivative, Net Liability Position, Aggregate Fair Value	174.7	$ 233
Cash collateral to request from interest rate derivative counterparty	2.8
Interest Rate Derivative, net asset position	$ 2.8

DERIVATIVE FINANCIAL INSTRUME44

DERIVATIVE FINANCIAL INSTRUMENTS Derivative Financial Instruments Offsetting Assets and Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ 223	$ 289
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability	223	289
Derivative, Collateral, Right to Reclaim Securities	(3)	0
Derivative, Collateral, Right to Reclaim Cash	(148)	(152)
Derivative Asset, Fair Value, Gross Asset	21	21
Derivative Asset, Fair Value, Gross Liability	0	0
Derivative Asset	21	21
Derivative, Collateral, Obligation to Return Securities	(3)	0
Derivative Asset, Fair Value, Amount Offset Against Collateral	18	21
Derivative, Collateral, Right to Reclaim Cash	0	0
Derivative Liability, Fair Value, Amount Offset Against Collateral	72	137
Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	11	5
Other Current Assets [Member]
Derivative [Line Items]
Derivative Liability	3	6
Derivative Asset	10	16
Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	125	233
Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability	95	50
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	202	257
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability	202	257
Derivative, Collateral, Right to Reclaim Securities	(3)	0
Derivative, Collateral, Right to Reclaim Cash	(135)	(131)
Derivative Asset, Fair Value, Gross Asset	6
Derivative Asset, Fair Value, Gross Liability	0
Derivative Asset	6
Derivative, Collateral, Obligation to Return Securities	(3)
Derivative Asset, Fair Value, Amount Offset Against Collateral	3
Derivative, Collateral, Right to Reclaim Cash	0
Derivative Liability, Fair Value, Amount Offset Against Collateral	64	126
Commodity Contract [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	7	12
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability	7	12
Derivative, Collateral, Right to Reclaim Securities	0	0
Derivative, Collateral, Right to Reclaim Cash	(6)	(10)
Derivative Asset, Fair Value, Gross Asset		1
Derivative Asset, Fair Value, Gross Liability		0
Derivative Asset		1
Derivative, Collateral, Obligation to Return Securities		0
Derivative Asset, Fair Value, Amount Offset Against Collateral		1
Derivative, Collateral, Right to Reclaim Cash		0
Derivative Liability, Fair Value, Amount Offset Against Collateral	1	2
Other Energy Management Contract [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	14	20
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability	14	20
Derivative, Collateral, Right to Reclaim Securities	0	0
Derivative, Collateral, Right to Reclaim Cash	(7)	(11)
Derivative Asset, Fair Value, Gross Asset	15	20
Derivative Asset, Fair Value, Gross Liability	0	0
Derivative Asset	15	20
Derivative, Collateral, Obligation to Return Securities	0	0
Derivative Asset, Fair Value, Amount Offset Against Collateral	15	20
Derivative, Collateral, Right to Reclaim Cash	0	0
Derivative Liability, Fair Value, Amount Offset Against Collateral	7	9
SCEG
Derivative [Line Items]
Derivative Liability	178	233
SCEG | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	6
SCEG | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	108	208
SCEG | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability	70	25
SCEG | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	178	233
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability	178	233
Derivative, Collateral, Right to Reclaim Securities	(3)	0
Derivative, Collateral, Right to Reclaim Cash	(109)	(107)
Derivative Asset, Fair Value, Gross Asset	6
Derivative Asset, Fair Value, Gross Liability	0
Derivative Asset	6
Derivative, Collateral, Obligation to Return Securities	(3)
Derivative Asset, Fair Value, Amount Offset Against Collateral	3
Derivative, Collateral, Right to Reclaim Cash	0
Derivative Liability, Fair Value, Amount Offset Against Collateral	$ 66	$ 126

FAIR VALUE MEASUREMENTS, INCL45

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	$ 21	$ 21
Derivative Liability	223	289
Available-for-sale Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	13	13
Available-for-sale Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	0	0
Interest Rate Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	6
Derivative Liability	202	257
Interest Rate Contract | Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Interest Rate Contract | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	6	0
Derivative Liability	202	257
Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset		1
Derivative Liability	7	12
Commodity Contract | Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	0	1
Derivative Liability	1	1
Commodity Contract | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	0	0
Derivative Liability	6	11
Other energy management contracts [Member] [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	15	20
Derivative Liability	14	20
Other energy management contracts [Member] [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	0	0
Derivative Liability	2	5
Other energy management contracts [Member] [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	15	20
Derivative Liability	15	18
SCEG
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Liability	178	233
SCEG | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	6
Derivative Liability	178	233
SCEG | Interest Rate Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	6
Derivative Liability	$ 178	$ 233

FAIR VALUE MEASUREMENTS, INCL46

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details 2) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014	Sep. 30, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	$ 6,034.3	$ 5,697.2
Long-term Debt, Fair Value		6,592.1	$ 6,623.3
SCEG
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	4,801	4,308.6
Long-term Debt, Fair Value	$ 5,277.6	$ 5,070.9

EMPLOYEE BENEFIT PLANS (Details

EMPLOYEE BENEFIT PLANS (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2013
Pension and Other Postretirement Benefit Plans
Pension Contributions			No
Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	$ 6.6	$ 5	$ 18.1	$ 15
Interest cost	9.6	9.9	28.7	30.3
Expected return on assets	(15.5)	(16.4)	(46.5)	(50)
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	1	1.1	3	3.1
Defined Benefit Plan, Actuarial Net (Gains) Losses	3.2	0.9	10.2	3.5
Defined Benefit Plan, Net Periodic Benefit Cost	4.9	0.5	13.5	1.9
Other Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	1.2	0.9	4	3.4
Interest cost	2.8	2.8	8.6	9
Expected return on assets	0	0	0	0
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	0.1	0.1	0.3	0.3
Defined Benefit Plan, Actuarial Net (Gains) Losses	0.4	(0.2)	1.5	0
Defined Benefit Plan, Net Periodic Benefit Cost	4.5	3.6	$ 14.4	12.7
SCEG
Pension and Other Postretirement Benefit Plans
Pension Contributions			No
SCEG | Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	5.3	4	$ 14.5	12
Interest cost	8.1	8.4	24.1	25.6
Expected return on assets	(13)	(13.9)	(39.1)	(42.2)
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	0.8	0.9	2.5	2.6
Defined Benefit Plan, Actuarial Net (Gains) Losses	2.7	0.8	8.6	3
Defined Benefit Plan, Net Periodic Benefit Cost	3.9	0.2	10.6	1
SCEG | Other Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	1	0.7	3.2	2.7
Interest cost	2.2	2.3	6.8	7.1
Expected return on assets	0	0	0	0
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	0.1	0	0.2	0.2
Defined Benefit Plan, Actuarial Net (Gains) Losses	0.3	(0.2)	1.2	0
Defined Benefit Plan, Net Periodic Benefit Cost	$ 3.6	$ 2.8	$ 11.4	$ 10
Pension Costs [Member] | SCEG
Components of Net Periodic Benefit Cost
Regulatory Noncurrent Asset, Amortization Period			12 years		30 years

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Details) - USD ($)	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2013
Commitments and contingencies
Asset Retirement Obligation	$ 489,000,000	$ 563,000,000				$ 576,000,000
Asset Retirement Obligation, Liabilities Incurred	0	3,000,000
Asset Retirement Obligation, Liabilities Settled	(15,000,000)	(6,000,000)
Asset Retirement Obligation, Accretion Expense	20,000,000	26,000,000
Asset Retirement Obligation, Revision of Estimate	$ (79,000,000)	(36,000,000)
Nuclear Generation
Emission Rate Standard For Coal Fired Power Plants Under Clean Air Act	1,400
Emission Rate Standard For Gas Fired Power Plants Under Clean Air Act	1,000
Goal For Reduced Carbon Dioxide Emissions From 2005 Levels By 2030 Under Clean Air Act	32.00%
NPDES permit renewal permit period	five
Forecasted Incremental Capital Costs Associated With Schedule Delays, 2015 Petition	$ 539,000,000
EPC Contract Amendment, New Nuclear Construction Completion Bonus	151,000,000
EPC Contract Amendment, Fixed Price Option, Increase In Total New Nuclear Project Cost	774,000,000
Regulatory Assets, Noncurrent	1,884,000,000	1,823,000,000
Asset Retirement Obligation Other Conditional Obligations	315,000,000	362,000,000
SCEG
Commitments and contingencies
Asset Retirement Obligation	460,000,000	536,000,000				$ 547,000,000
Asset Retirement Obligation, Liabilities Incurred	0	3,000,000
Asset Retirement Obligation, Liabilities Settled	(15,000,000)	(6,000,000)
Asset Retirement Obligation, Accretion Expense	18,000,000	25,000,000
Asset Retirement Obligation, Revision of Estimate	(79,000,000)	(33,000,000)
Nuclear Insurance
Federal Limit on Public Liability Claims from Nuclear Incident Approximate	12,900,000,000
Maximum Insurance Coverage for each Nuclear Plant by ANI	375,000,000
Maximum liability assessment per reactor for each nuclear incident	127,300,000
Maximum Federal Limit on Public Liability Claims Per Incident for Each Year	12,600,000
Maximum yearly assessment per reactor	18,900,000
Maximum Federal Limit on Public Liability Claims per Reactor for each Nuclear Incident at 2/3	$ 84,800,000
Inflation adjustment period for nuclear insurance	5
Maximum retrospective insurance premium per nuclear incident	$ 45,900,000
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
Maximum loss for a single nuclear incident	$ 2,750,000,000
Environmental
Number of MGP decommissioned sites that contain residues of byproduct chemicals	4
Site Contingency MGP Estimated Environmental Remediation Costs	$ 19,000,000
Deferred costs net of costs previously recovered through rates and insurance settlements included in regulatory assets	$ 34,700,000
Nuclear Generation
Current ownership share in New Unit	55.00%
Total additional ownership in new units	5.00%
Additional ownership in new units	1.00%
Additional ownership in new units, dollars	$ 750,000,000
Emission Rate Standard For Coal Fired Power Plants Under Clean Air Act	1,400
Emission Rate Standard For Gas Fired Power Plants Under Clean Air Act	1,000
Goal For Reduced Carbon Dioxide Emissions From 2005 Levels By 2030 Under Clean Air Act	0.00%
EPC Contract Amendment, Settlement Of Outstanding New Nuclear Construction Disputes	$ 165,000,000
EPC Contract Amendment, Credit Applied To Target Component Of New Units Contract Price	27,000,000
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 Approved By SCPSC Including Fixed Option Price Increase	7,600,000,000
EPC Contract Amendment, Total New Nuclear Project Cost Approved By SCPSC Including Amendment Increase	7,000,000,000
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
Regulatory Assets, Noncurrent	1,808,000,000	1,745,000,000
Asset Retirement Obligation Nuclear Decommissioning	174,000,000	201,000,000
Asset Retirement Obligation Other Conditional Obligations	286,000,000	$ 335,000,000
Summer Station New Units [Domain]
Nuclear Insurance
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	3,300,000,000
jointly owned utility plant ownership, construction financing cost	$ 2,425,000,000
Nuclear Generation
Jointly Owned Utility Plant, Proportionate Ownership Share	55.00%
Jointly Owned Utility Plant, Additional Ownership Of New Units	5.00%
Nuclear Production Tax Credits	$ 1,400,000,000
Nuclear Production Tax Credit realization period	8
EPC Contract Amendment, Settlement Of Outstanding New Nuclear Construction Disputes	$ 300,000,000
EPC Contract Amendment, Credit Applied To Target Component Of New Units Contract Price	50,000,000
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
Summer Station New Units [Domain] | SCEG
Nuclear Generation
Jointly Owned Utility Plant, Proportionate Ownership Share	55.00%
Nuclear Production Tax Credits	$ 1,400,000,000
Nuclear Production Tax Credit realization period	8
Capital costs, owners [Domain]
Nuclear Generation
Forecasted incremental capital costs, 2015 petition	$ 245,000,000
Forecasted Total Capital Costs, 2015 Petition	5,200,000,000
Capital costs, owners [Domain] | SCEG
Nuclear Generation
Forecasted incremental capital costs, 2015 petition	245,000,000
Capital costs, Other [Domain] [Domain]
Nuclear Generation
Forecasted incremental capital costs, 2015 petition	453,000,000
Forecasted Total Capital Costs, 2015 Petition	6,800,000,000
Capital costs, Other [Domain] [Domain] | SCEG
Nuclear Generation
Forecasted incremental capital costs, 2015 petition	$ 453,000,000
Scenario, Forecast [Member] | SCEG
Nuclear Generation
Additional ownership in new units			2.00%	2.00%	1.00%

SEGMENT OF BUSINESS INFORMATI49

SEGMENT OF BUSINESS INFORMATION (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2015	Mar. 31, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Segment Reporting Information [Line Items]
Gain (Loss) on Disposition of Nonregulated Business, Net of Transaction Costs		$ 201
Electric Domestic Regulated Revenue	$ 742		$ 739	$ 2,008	$ 2,027
Intersegment Revenue	0		0	0	0
Operating Income	(292)		(269)	(1,095)	(772)
Regulated Operating Revenue, Gas	112		132	610	740
Regulated and Unregulated Operating Revenue	1,068		1,121	3,423	3,736
Income Available to Common Shareholders	149		144	648	433
Segment Assets	16,506			16,506		$ 16,852
Electric Operations
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue	742		739	2,008	2,027
Intersegment Revenue	1		1	4	5
Operating Income	(313)		(275)	(728)	(616)
Segment Assets	10,531			10,531		10,182
Gas Distribution
Segment Reporting Information [Line Items]
Intersegment Revenue	2		0	2	0
Operating Income	13		6	(88)	(98)
Regulated and Unregulated Operating Revenue	112		127	609	728
Segment Assets	2,498			2,498		2,487
Retail Gas Marketing
Segment Reporting Information [Line Items]
Intersegment Revenue	0		0	0	0
Regulated and Unregulated Operating Revenue	68		68	344	367
Income Available to Common Shareholders	(3)		(3)	18	16
Segment Assets	107			107		140
Energy Marketing [Member]
Segment Reporting Information [Line Items]
Intersegment Revenue	34		47	101	154
Regulated and Unregulated Operating Revenue	146		182	461	602
Income Available to Common Shareholders	(1)		(2)	8	5
Segment Assets	102			102		150
All Other [member]
Segment Reporting Information [Line Items]
Intersegment Revenue	102		103	309	317
Operating Income	0		(7)	(237)	(21)
Regulated and Unregulated Operating Revenue	0		9	5	27
Income Available to Common Shareholders	(9)		(5)	188	(3)
Segment Assets	998			998		1,474
Adjustments/Eliminations
Segment Reporting Information [Line Items]
Intersegment Revenue	(139)		(151)	(416)	(476)
Operating Income	(8)		7	(42)	(37)
Regulated and Unregulated Operating Revenue	0		(4)	(4)	(15)
Income Available to Common Shareholders	162		154	434	415
Segment Assets	2,270			2,270		2,419
SCEG
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue	743		740	2,013	2,032
Operating Income	(307)		(272)	(763)	(656)
Regulated Operating Revenue, Gas	63		72	275	337
Net Income (Loss) Attributable to Parent	164		154	394	374
Segment Assets	14,312			14,312		14,107
Regulated Operating Revenue	806		812	2,288	2,369
SCEG | Electric Operations
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue	743		740	2,013	2,032
Operating Income	(313)		(274)	(728)	(616)
Segment Assets	10,531			10,531		10,182
SCEG | Gas Distribution
Segment Reporting Information [Line Items]
Operating Income	6		2	(35)	(40)
Regulated Operating Revenue, Gas	63		72	275	337
Segment Assets	749			749		721
SCEG | Adjustments/Eliminations
Segment Reporting Information [Line Items]
Operating Income	0		0	0	0
Net Income (Loss) Attributable to Parent	164		154	394	374
Segment Assets	3,032			3,032		$ 3,204
Regulated Operating Revenue	$ 0		$ 0	$ 0	$ 0

AFFILIATED TRANSACTIONS -SCEG (

AFFILIATED TRANSACTIONS -SCEG (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Canadys Refined Coal [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction	$ 65.9	$ 82	$ 185.1	$ 190.9
Due to Affiliate, Current	21.8		21.8		$ 27.9
Due from Affiliate, Current	$ 21.6		$ 21.6		27.8
Equity Method Investment, Ownership Percentage	40.00%		40.00%
CGT [Member]
Related Party Transaction [Line Items]
Related Party Transaction Purchases from Related Party		6.9	$ 3.4	21.6
Due to Affiliate, Current					3.3
Due from Affiliate, Current		0		0	1.2
Energy Marketing [Member]
Related Party Transaction [Line Items]
Due to Affiliate, Current	$ 9.6		9.6		12.6
Cost of Natural Gas Purchases	34	46.8	101.4	154.1
Canadys Refined Coal [Member]
Related Party Transaction [Line Items]
Related Party Transaction Purchases from Related Party	66.3	82.4	186	191.9
SCANA Services [Member]
Related Party Transaction [Line Items]
Due to Affiliate, Current	37.2		37.2		$ 47.3
Related Party Transaction, Expenses from Transactions with Related Party	$ 80.8	$ 65	$ 226	$ 211.4

Dispositions (Details)

Dispositions (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Public Utilities, Property, Plant and Equipment, Net	$ 12,729	$ 12,232
Nonutility Property and Investments, Net	467	472
Assets, Current	1,221	2,145
Regulated Entity, Other Assets, Noncurrent	2,089	2,003
Assets held for sale	0	341
Liabilities, Current	1,294	2,533
Liabilities, Noncurrent	3,775	3,801
Liabilities held for sale		52
Estimated pre-tax gain on sale of CGT and SCI	$ 342
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
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
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
Assets held for sale		340.6
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