10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2016

Commission	Registrant, State of Incorporation,	I.R.S. Employer
File Number	Address and Telephone Number	Identification No.
1-8809	SCANA Corporation(a South Carolina corporation)	57-0784499
1-3375	South Carolina Electric & Gas Company(a South Carolina corporation)	57-0248695
	100 SCANA Parkway, Cayce, South Carolina 29033
	(803) 217-9000

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. SCANA Corporation Yes x No o  South Carolina Electric & Gas Company Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). SCANA Corporation Yes x No o  South Carolina Electric & Gas Company Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

SCANA Corporation	Large accelerated filer  x	Accelerated filer  o	Non-accelerated filer  o
	Smaller reporting company  o
South Carolina Electric & Gas Company	Large accelerated filer  o	Accelerated filer  o	Non-accelerated filer  x
	Smaller reporting company  o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

SCANA Corporation Yes o No x  South Carolina Electric & Gas Company Yeso No x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

	Description of	Shares Outstanding
Registrant	Common Stock	at April 30, 2016
SCANA Corporation	Without Par Value	142,916,917
South Carolina Electric & Gas Company	Without Par Value	40,296,147 (a)

(a) Held beneficially and of record by SCANA Corporation.

This combined Form 10-Q is separately filed by SCANA Corporation and South Carolina Electric & Gas Company.  Information contained herein relating to any individual registrant is filed by such registrant on its own behalf.  South Carolina Electric & Gas Company makes no representation as to information relating to SCANA Corporation or its subsidiaries (other than South Carolina Electric & Gas Company and its consolidated affiliates).

South Carolina Electric & Gas Company meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and therefore is filing this Form with the reduced disclosure format allowed under General Instruction H(2).

			Page
Cautionary Statement Regarding Forward-Looking Information			3
Definitions			4
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements			6
	SCANA Corporation		6
		Condensed Consolidated Balance Sheets	6
		Condensed Consolidated Statements of Income	8
		Condensed Consolidated Statements of Comprehensive Income	9
		Condensed Consolidated Statements of Cash Flows	10
		Condensed Consolidated Statements of Changes in Common Equity	11
	South Carolina Electric & Gas Company		12
		Condensed Consolidated Balance Sheets	12
		Condensed Consolidated Statements of Income	14
		Condensed Consolidated Statements of Comprehensive Income	14
		Condensed Consolidated Statements of Cash Flows	15
		Condensed Consolidated Statements of Changes in Equity	16
	Combined Notes to Condensed Consolidated Financial Statements		17
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations			38
	SCANA Corporation		38
	South Carolina Electric & Gas Company		43
Item 3. Quantitative and Qualitative Disclosures About Market Risk			45
Item 4. Controls and Procedures			46
PART II. OTHER INFORMATION
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			47
Item 5. Other Information			47
Item 6. Exhibits			47
Signatures			48
Exhibit Index			49

2

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

Statements included in this Quarterly Report on Form 10-Q which are not statements of historical fact are intended to be, and are hereby identified as, “forward-looking statements” for purposes of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.  Forward-looking statements include, but are not limited to, statements concerning key earnings drivers, customer growth, environmental regulations and expenditures, leverage ratio, projections for pension fund contributions, financing activities, access to sources of capital, impacts of the adoption of new accounting rules and estimated construction and other expenditures.  In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “forecasts,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential” or “continue” or the negative of these terms or other similar terminology.  Readers are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, and that actual results could differ materially from those indicated by such forward-looking statements.  Important factors that could cause actual results to differ materially from those indicated by such forward-looking statements include, but are not limited to, the following:

(1) the information is of a preliminary nature and may be subject to further and/or continuing review and adjustment;

(2) legislative and regulatory actions, particularly changes in electric and gas services, rate regulation, regulations governing electric grid reliability and pipeline integrity, environmental regulations, and actions affecting the construction of new nuclear units;

(3) current and future litigation;

(4) changes in the economy, especially in areas served by subsidiaries of SCANA;

(5) the impact of competition from other energy suppliers, including competition from alternate fuels in industrial markets;

(6) the impact of conservation and demand side management efforts and/or technological advances on customer usage;

(7) the loss of sales to distributed generation, such as solar photovoltaic systems;

(8) growth opportunities for SCANA’s regulated and other subsidiaries;

(9) the results of short- and long-term financing efforts, including prospects for obtaining access to capital markets and other sources of liquidity;

(10) the effects of weather, especially in areas where the generation and transmission facilities of SCANA and its

subsidiaries (the Company) are located and in areas served by SCANA’s subsidiaries;

(11) changes in SCANA’s or its subsidiaries’ accounting rules and accounting policies;

(12)payment and performance by counterparties and customers as contracted and when due;

(13) the results of efforts to license, site, construct and finance facilities for electric generation and transmission, including nuclear generating facilities;

(14) the results of efforts to operate the Company's electric and gas systems and assets in accordance with acceptable performance standards, including the impact of additional distributed generation and nuclear generation;

(15) maintaining creditworthy joint owners for SCE&G’s new nuclear generation project;

(16) the ability of suppliers, both domestic and international, to timely provide the labor, secure processes, components, parts, tools, equipment and other supplies needed, at agreed upon quality and prices, for our construction program, operations and maintenance;

(17) the results of efforts to ensure the physical and cyber security of key assets and processes;

(18) the availability of fuels such as coal, natural gas and enriched uranium used to produce electricity; the availability of purchased power and natural gas for distribution; the level and volatility of future market prices for such fuels and purchased power; and the ability to recover the costs for such fuels and purchased power;

(19) the availability of skilled, licensed and experienced human resources to properly manage, operate, and grow the Company’s businesses;

(20) labor disputes;

(21) performance of SCANA’s pension plan assets;

(22) changes in tax laws and realization of tax benefits and credits, including production tax credits for new nuclear units;

(23) inflation or deflation;

(24) compliance with regulations;

(25) natural disasters and man-made mishaps that directly affect our operations or the regulations governing them; and

(26) the other risks and uncertainties described from time to time in the reports filed by SCANA or SCE&G with the SEC.

SCANA and SCE&G disclaim any obligation to update any forward-looking statements.

3

DEFINITIONS

The following abbreviations used in the text have the meanings set forth below unless the context requires otherwise: 

TERM	MEANING
AFC	Allowance for Funds Used During Construction
ANI	American Nuclear Insurers
AOCI	Accumulated Other Comprehensive Income
ARO	Asset Retirement Obligation
BLRA	Base Load Review Act
CAIR	Clean Air Interstate Rule
CB&I	Chicago Bridge & Iron Company N.V.
CCR	Coal Combustion Residuals
CEO	Chief Executive Officer
CFO	Chief Financial Officer
CGT	Carolina Gas Transmission Corporation
COL	Combined Construction and Operating License
Company	SCANA, together with its consolidated subsidiaries
Consolidated SCE&G	SCE&G and its consolidated affiliates
Consortium	A consortium consisting of WEC and Stone & Webster
Court of Appeals	United States Court of Appeals for the District of Columbia
CSAPR	Cross-State Air Pollution Rule
CUT	Customer Usage Tracker
CWA	Clean Water Act
DCGT	Dominion Carolina Gas Transmission, LLC
DER	Distributed Energy Resource
DHEC	South Carolina Department of Health and Environmental Control
DOE	United States Department of Energy
DSM Programs	Demand Side Management Programs
ELG Rule	Federal effluent limitation guidelines for steam electric generating units
EMANI	European Mutual Association for Nuclear Insurance
Energy Marketing	The divisions of SEMI, excluding SCANA Energy
EPA	United States Environmental Protection Agency
EPC Contract	Engineering, Procurement and Construction Agreement dated May 23, 2008
FASB	Financial Accounting Standards Board
FERC	United States Federal Energy Regulatory Commission
Fuel Company	South Carolina Fuel Company, Inc.
GAAP	Accounting principles generally accepted in the United States of America
GENCO	South Carolina Generating Company, Inc.
GHG	Greenhouse Gas
GWh	Gigawatt hour
IRS	Internal Revenue Service
Level 1	A fair value measurement using unadjusted quoted prices in active markets for identical assets or liabilities
Level 2	A fair value measurement using observable inputs other than those for Level 1, including quoted prices for similar (not identical) assets or liabilities or inputs that are derived from observable market data by correlation or other means
Level 3	A fair value measurement using unobservable inputs, including situations where there is little, if any, market activity for the asset or liability
LOC	Lines of Credit
MATS	Mercury and Air Toxics Standards
MGP	Manufactured Gas Plant

4

MMBTU	Million British Thermal Units
MW	Megawatt
NAAQS	National Ambient Air Quality Standards
NASDAQ	The NASDAQ Stock Market, Inc.
NCUC	North Carolina Utilities Commission
NEIL	Nuclear Electric Insurance Limited
New Units	Nuclear Units 2 and 3 under construction at Summer Station
NPDES	National Permit Discharge Elimination System
NRC	United States Nuclear Regulatory Commission
Nuclear Waste Act	Nuclear Waste Policy Act of 1982
NYMEX	New York Mercantile Exchange
OCI	Other Comprehensive Income
October 2015 Amendment	Amendment, dated October 27,2015, to the EPC Contract
ORS	South Carolina Office of Regulatory Staff
Price-Anderson	Price-Anderson Indemnification Act
PSNC Energy	Public Service Company of North Carolina, Incorporated
Retail Gas Marketing	SCANA Energy
RSA	Natural Gas Rate Stabilization Act
Santee Cooper	South Carolina Public Service Authority
SCANA	SCANA Corporation, the parent company
SCANA Energy	A division of SEMI which markets natural gas in Georgia
SCE&G	South Carolina Electric & Gas Company
SCI	SCANA Communications, Inc.
SCPSC	Public Service Commission of South Carolina
SEC	United States Securities and Exchange Commission
SEMI	SCANA Energy Marketing, Inc.
SIP	State Implementation Plan
Spirit Communications	SCTG Communications, Inc. (a wholly owned subsidiary of SCTG, LLC) d/b/a Spirit Communications
Stone & Webster	Stone & Webster, a subsidiary of WECTEC, LLC, a wholly-owned subsidiary of WEC
Summer Station	V. C. Summer Nuclear Station
Supreme Court	United States Supreme Court
VIE	Variable Interest Entity
WEC	Westinghouse Electric Company LLC
WNA	Weather Normalization Adjustment

5

PART I.  FINANCIAL INFORMATION

ITEM 1. F INANCIAL STATEMENTS

SCANA Corporation and Subsidiaries

Condensed Consolidated Balance Sheets

(Unaudited) 

Millions of dollars	March 31, 2016			December 31, 2015
Assets
Utility Plant In Service	$	12,942		$	12,883
Accumulated Depreciation and Amortization	(4,327		)	(4,307		)
Construction Work in Progress	4,245			4,051
Nuclear Fuel, Net of Accumulated Amortization	295			308
Goodwill, net of writedown of $230	210			210
Utility Plant, Net	13,365			13,145
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation of $128 and $124	280			280
Assets held in trust, net-nuclear decommissioning	119			115
Other investments	73			71
Nonutility Property and Investments, Net	472			466
Current Assets:
Cash and cash equivalents	86			176
Receivables:
Customer, net of allowance for uncollectible accounts of $5 and $5	505			505
Other	142			227
Inventories (at average cost):
Fuel and gas supply	134			164
Materials and supplies	148			148
Prepayments	119			115
Other current assets	83			43
Total Current Assets	1,217			1,378
Deferred Debits and Other Assets:
Regulatory assets	2,068			1,937
Other	246			220
Total Deferred Debits and Other Assets	2,314			2,157
Total	$	17,368		$	17,146

See Combined Notes to Condensed Consolidated Financial Statements.

6

Millions of dollars	March 31, 2016			December 31, 2015
Capitalization and Liabilities
Common Stock - no par value, 142.9 million shares outstanding	$	2,390		$	2,390
Retained Earnings	3,212			3,118
Accumulated Other Comprehensive Loss	(63		)	(65		)
Total Common Equity	5,539			5,443
Long-Term Debt, net	5,879			5,882
Total Capitalization	11,418			11,325
Current Liabilities:
Short-term borrowings	917			531
Current portion of long-term debt	116			116
Accounts payable	369			590
Customer deposits and customer prepayments	176			137
Taxes accrued	83			242
Interest accrued	85			83
Dividends declared	80			76
Derivative financial instruments	113			50
Other	92			127
Total Current Liabilities	2,031			1,952
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,898			1,907
Asset retirement obligations	522			520
Pension and other postretirement benefits	318			315
Regulatory liabilities	847			855
Other	334			272
Total Deferred Credits and Other Liabilities	3,919			3,869
Commitments and Contingencies (Note 9)
Total	$	17,368		$	17,146

See Combined Notes to Condensed Consolidated Financial Statements.

7

SCANA Corporation and Subsidiaries

Condensed Consolidated Statements of Income

(Unaudited)

	Three Months Ended
	March 31,
Millions of dollars, except per share amounts	2016			2015
Operating Revenues:
Electric	$	592		$	629
Gas - regulated	299			369
Gas - nonregulated	281			391
Total Operating Revenues	1,172			1,389
Operating Expenses:
Fuel used in electric generation	136			174
Purchased power	11			13
Gas purchased for resale	359			523
Other operation and maintenance	181			173
Depreciation and amortization	91			96
Other taxes	63			59
Total Operating Expenses	841			1,038
Gain on sale of CGT, net of transaction costs	—			235
Operating Income	331			586
Other Income (Expense):
Other income	16			19
Other expense	(14		)	(12		)
Gain on sale of SCI, net of transaction costs	—			107
Interest charges, net of allowance for borrowed funds used during construction of $4 and $3	(83		)	(77		)
Allowance for equity funds used during construction	5			5
Total Other Income (Expense)	(76		)	42
Income Before Income Tax Expense	255			628
Income Tax Expense	79			228
Net Income	$	176		$	400
Earnings Per Share of Common Stock	$	1.23		$	2.80
Weighted Average Common Shares Outstanding (millions)	142.9			142.9
Dividends Declared Per Share of Common Stock	$	0.575		$	0.545

See Combined Notes to Condensed Consolidated Financial Statements.

8

SCANA Corporation and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income

(Unaudited) 

	Three Months Ended March 31,
Millions of dollars	2016			2015
Net Income	$	176		$	400
Other Comprehensive Income (Loss), net of tax:
Unrealized Gains (Losses) on Cash Flow Hedging Activities:
Unrealized losses on cash flow hedging activities arising during period, net of tax of $(3) and $(2)	(5		)	(3		)
Cash flow hedging activities reclassified to interest expense, net of tax of $1 and $1	2			2
Cash flow hedging activities reclassified to gas purchased for resale, net of tax of $3 and $5	5			7
Net unrealized gains on cash flow hedging activities	2			6
Deferred cost of employee benefit plans, net of tax of $- and $(3)	—			(4		)
Other Comprehensive Income	2			2
Total Comprehensive Income	$	178		$	402

See Combined Notes to Condensed Consolidated Financial Statements.

9

SCANA Corporation and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(Unaudited) 

	Three Months Ended March 31,
Millions of dollars	2016			2015
Cash Flows From Operating Activities:
Net income	$	176		$	400
Adjustments to reconcile net income to net cash provided from operating activities:
Gain on sale of subsidiaries	—			(353		)
Losses from equity method investments	—			1
Deferred income taxes, net	(11		)	(74		)
Depreciation and amortization	94			100
Amortization of nuclear fuel	14			13
Allowance for equity funds used during construction	(5		)	(5		)
Carrying cost recovery	(4		)	(3		)
Changes in certain assets and liabilities:				—
Receivables	—			33
Inventories	11			31
Prepayments	(11		)	218
Regulatory assets	—			28
Regulatory liabilities	(1		)	6
Accounts payable	(39		)	(67		)
Taxes accrued	(159		)	(71		)
Derivative financial instruments	(3		)	(22		)
Other assets	(20		)	(6		)
Other liabilities	19			(34		)
Net Cash Provided From Operating Activities	61			195
Cash Flows From Investing Activities:
Property additions and construction expenditures	(385		)	(352		)
Proceeds from sale of subsidiaries	—			645
Proceeds from investments (including derivative collateral returned)	198			318
Purchase of investments (including derivative collateral posted)	(264		)	(400		)
Net Cash Provided From (Used For) Investing Activities	(451		)	211
Cash Flows From Financing Activities:
Proceeds from issuance of common stock	—			14
Repayment of long-term debt	(8		)	(158		)
Dividends	(78		)	(75		)
Short-term borrowings, net	386			(293		)
Net Cash Provided From (Used for) Financing Activities	300			(512		)
Net Decrease In Cash and Cash Equivalents	(90		)	(106		)
Cash and Cash Equivalents, January 1	176			137
Cash and Cash Equivalents, March 31	$	86		$	31
Supplemental Cash Flow Information:
Cash paid for– Interest (net of capitalized interest of $4 and $3)	$	77		$	81
– Income taxes	141			8
Noncash Investing and Financing Activities:
Accrued construction expenditures	142			84
Capital leases	5			2

 See Combined Notes to Condensed Consolidated Financial Statements.

10

SCANA Corporation and Subsidiaries

Condensed Consolidated Statements of Changes in Common Equity

(Unaudited)

	Common Stock									Accumulated Other Comprehensive Income (Loss)
Millions	Shares	Outstanding Amount		Treasury Shares			Retained Earnings			Gains (Losses) Cash Flow Hedges			Deferred Employee Benefit Plans			Total AOCI			Total
Balance as of January 1, 2016	143	$	2,402	$	(12	)	$	3,118		$	(53	)	$	(12	)	$	(65	)	$	5,443
Net Income							176												176
Other Comprehensive Income (Loss)
Losses arising during the period										(5		)	—			(5		)	(5		)
Losses/amortization reclassified from AOCI										7			—			7			7
Total Comprehensive Income							176			2			—			2			178
Dividends Declared							(82		)										(82		)
Balance as of March 31, 2016	143	$	2,402	$	(12	)	$	3,212		$	(51	)	$	(12	)	$	(63	)	$	5,539
Balance as of January 1, 2015	143	$	2,388	$	(10	)	$	2,684		$	(63	)	$	(12	)	$	(75	)	$	4,987
Net Income							400												400
Other Comprehensive Income (Loss)
Losses arising during the period										(3		)	(4		)	(7		)	(7		)
Losses/amortization reclassified from AOCI										9			—			9			9
Total Comprehensive Income (Loss)							400			6			(4		)	2			402
Issuance of Common Stock	—	14																	14
Dividends Declared							(78		)										(78		)
Balance as of March 31, 2015	143	$	2,402	$	(10	)	$	3,006		$	(57	)	$	(16	)	$	(73	)	$	5,325

Dividends declared per share of common stock were $0.575 and $0.545 for March 31, 2016 and 2015, respectively.

See Combined Notes to Condensed Consolidated Financial Statements.

11

South Carolina Electric & Gas Company and Affiliates

Condensed Consolidated Balance Sheets

(Unaudited)

Millions of dollars	March 31, 2016			December 31, 2015
Assets
Utility Plant In Service	$	11,195		$	11,153
Accumulated Depreciation and Amortization	(3,883		)	(3,869		)
Construction Work in Progress	4,141			3,997
Nuclear Fuel, Net of Accumulated Amortization	295			308
Utility Plant, Net ($683 and $700 related to VIEs)	11,748			11,589
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	68			68
Assets held in trust, net-nuclear decommissioning	119			115
Other investments	1			1
Nonutility Property and Investments, Net	188			184
Current Assets:
Cash and cash equivalents	57			130
Receivables:
Customer, net of allowance for uncollectible accounts of $3 and $3	320			324
Affiliated companies	15			22
Other	114			202
Inventories (at average cost):
Fuel	92			98
Materials and supplies	135			136
Prepayments	87			92
Other current assets	52			15
Total Current Assets ($90 and $88 related to VIEs)	872			1,019
Deferred Debits and Other Assets:
Regulatory assets	1,986			1,857
Other	138			116
Total Deferred Debits and Other Assets ($58 and $53 related to VIEs)	2,124			1,973
Total	$	14,932		$	14,765

See Combined Notes to Condensed Consolidated Financial Statements.

12

Millions of dollars	March 31, 2016			December 31, 2015
Capitalization and Liabilities
Common Stock - no par value, 40.3 million shares outstanding	$	2,760		$	2,760
Retained Earnings	2,306			2,265
Accumulated Other Comprehensive Loss	(3		)	(3		)
Total Common Equity	5,063			5,022
Noncontrolling Interest	130			129
Total Equity	5,193			5,151
Long-Term Debt, net	4,656			4,659
Total Capitalization	9,849			9,810
Current Liabilities:
Short-term borrowings	870			420
Current portion of long-term debt	111			110
Accounts payable	245			469
Affiliated payables	116			113
Customer deposits and customer prepayments	129			93
Taxes accrued	76			299
Interest accrued	66			66
Dividends declared	74			75
Derivative financial instruments	101			34
Other	42			61
Total Current Liabilities	1,830			1,740
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,717			1,732
Asset retirement obligations	490			488
Pension and other postretirement benefits	188			186
Regulatory liabilities	623			635
Other	218			157
Other affiliate	17			17
Total Deferred Credits and Other Liabilities	3,253			3,215
Commitments and Contingencies (Note 9)
Total	$	14,932		$	14,765

See Combined Notes to Condensed Consolidated Financial Statements.

13

South Carolina Electric & Gas Company and Affiliates

Condensed Consolidated Statements of Income

(Unaudited) 

	Three Months Ended
	March 31,
Millions of dollars	2016			2015
Operating Revenues:
Electric	$	593		$	630
Gas	124			142
Total Operating Revenues	717			772
Operating Expenses:
Fuel used in electric generation	136			174
Purchased power	11			13
Gas purchased for resale	56			74
Other operation and maintenance	146			139
Depreciation and amortization	74			80
Other taxes	58			55
Total Operating Expenses	481			535
Operating Income	236			237
Other Income (Expense):
Other income	5			9
Other expense	(8		)	(8		)
Interest charges, net of allowance for borrowed funds used during construction of $3 and $3	(66		)	(59		)
Allowance for equity funds used during construction	5			5
Total Other Income (Expense)	(64		)	(53		)
Income Before Income Tax Expense	172			184
Income Tax Expense	56			58
Net Income	116			126
Net Income Attributable to Noncontrolling Interest	(3		)	(4		)
Earnings Available to Common Shareholder	$	113		$	122
Dividends Declared on Common Stock	$	74		$	71

See Combined Notes to Condensed Consolidated Financial Statements.

South Carolina Electric & Gas Company and Affiliates

Condensed Consolidated Statements of Comprehensive Income

(Unaudited)

	Three Months Ended March 31,
Millions of dollars	2016			2015
Net Income and Total Comprehensive Income	$	116		$	126
Comprehensive income attributable to noncontrolling interest	(3		)	(4		)
Comprehensive income available to common shareholder	$	113		$	122

See Combined Notes to Condensed Consolidated Financial Statements.

14

South Carolina Electric & Gas Company and Affiliates

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	Three Months Ended March 31,
Millions of dollars	2016			2015
Cash Flows From Operating Activities:
Net income	$	116		$	126
Adjustments to reconcile net income to net cash provided from operating activities:
Losses from equity method investments	1			1
Deferred income taxes, net	(15		)	7
Depreciation and amortization	76			82
Amortization of nuclear fuel	14			13
Allowance for equity funds used during construction	(5		)	(5		)
Carrying cost recovery	(4		)	(3		)
Changes in certain assets and liabilities:
Receivables	7			(68		)
Receivables - affiliate	(2		)	90
Inventories	(3		)	—
Prepayments	(3		)	75
Regulatory assets	2			22
Regulatory liabilities	(1		)	6
Accounts payable	(23		)	(205		)
Accounts payable - affiliate	(8		)	185
Taxes accrued	(223		)	(50		)
Other assets	(9		)	(3		)
Other liabilities	25			(49		)
Net Cash Provided From (Used For) Operating Activities	(55		)	224
Cash Flows From Investing Activities:
Property additions and construction expenditures	(337		)	(319		)
Proceeds from investments (including derivative collateral returned)	171			274
Purchase of investments (including derivative collateral posted)	(239		)	(356		)
Proceeds from money pool investments	9			80
Net Cash Used For Investing Activities	(396		)	(321		)
Cash Flows From Financing Activities:
Repayment of long-term debt	(8		)	(8		)
Dividends	(75		)	(74		)
Return of capital to parent	—			(4		)
Money pool borrowings, net	11			192
Short-term borrowings, net	450			(99		)
Net Cash Provided From Financing Activities	378			7
Net Decrease In Cash and Cash Equivalents	(73		)	(90		)
Cash and Cash Equivalents, January 1	130			100
Cash and Cash Equivalents, March 31	$	57		$	10
Supplemental Cash Flow Information:
Cash paid for – Interest (net of capitalized interest of $3 and $3)	$	63		$	62
– Income taxes paid	175			—
– Income taxes received	7			83
Noncash Investing and Financing Activities:
Accrued construction expenditures	109			76
Capital leases	5			2

See Combined Notes to Condensed Consolidated Financial Statements.

15

South Carolina Electric & Gas Company and Affiliates

Condensed Consolidated Statements of Changes in Common Equity

(Unaudited)

	Common Stock				Retained			Accumulated Other Comprehensive			Noncontrolling			Total
Millions	Shares	Amount			Earnings			Income (Loss)			Interest			Equity
Balance at January 1, 2016	40	$	2,760		$	2,265		$	(3	)	$	129		$	5,151
Earnings available to common shareholder					113						3			116
Deferred cost of employee benefit plans								—						—
Total Comprehensive Income					113			—			3			116
Cash dividend declared					(72		)				(2		)	(74		)
Balance at March 31, 2016	40	$	2,760		$	2,306		$	(3	)	$	130		$	5,193
Balance at January 1, 2015	40	$	2,560		$	2,077		$	(3	)	$	123		$	4,757
Earnings available to common shareholder					122						4			126
Deferred cost of employee benefit plans								—						—
Total Comprehensive Income					122			—			4			126
Capital contributions returned to parent		(4		)										(4		)
Cash dividend declared					(69		)				(1		)	(70		)
Balance at March 31, 2015	40	$	2,556		$	2,130		$	(3	)	$	126		$	4,809

See Combined Notes to Condensed Consolidated Financial Statements.

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SCANA Corporation and Subsidiaries

South Carolina Electric & Gas Company and Affiliates

Combined Notes to Condensed Consolidated Financial Statements

(Unaudited)

The following unaudited notes to the condensed consolidated financial statements are a combined presentation. Except as otherwise indicated herein, each note applies to the Company and Consolidated SCE&G; however, Consolidated SCE&G makes no representation as to information relating solely to SCANA Corporation or its subsidiaries (other than Consolidated SCE&G).

The following notes should be read in conjunction with the Notes to Consolidated Financial Statements appearing in each company's Annual Report on Form 10-K for the year ended December 31, 2015. These are interim financial statements and, due to the seasonality of each company's business and matters that may occur during the rest of the year, the amounts reported in the Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the full year.  In the opinion of the respective company's management, the information furnished herein reflects all adjustments, all of a normal recurring nature, which are necessary for a fair statement of the results for the interim periods reported. In addition, the preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Consolidation and Variable Interest Entities

The condensed consolidated financial statements of the Company include, after eliminating intercompany balances and transactions, the accounts of the parent holding company and each of its subsidiaries, including Consolidated SCE&G. Accordingly, discussions regarding the Company's financial results necessarily include the results of Consolidated SCE&G.

SCE&G has determined that it has a controlling financial interest in GENCO and Fuel Company (which are considered to be VIEs) and, accordingly, Consolidated SCE&G's condensed consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. As a result, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s condensed consolidated financial statements.

GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $488 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.

Income Statement Presentation

Revenues and expenses arising from regulated businesses and, in the case of the Company, retail natural gas marketing businesses (including those activities of segments described in Note 10) are presented within operating income, and all other activities are presented within other income (expense). Consistent with this presentation, the Company presents the 2015 gain on the sale of CGT within operating income and the 2015 gain on the sale of SCI within other income (expense).

Asset Management and Supply Service Agreement

PSNC Energy, a subsidiary of SCANA, utilizes an asset management and supply service agreement with a counterparty for certain natural gas storage facilities.  Such counterparty held 29% and 46% of PSNC Energy’s natural gas inventory at March 31, 2016 and December 31, 2015, respectively, with a carrying value of $6.0 million and $17.7 million, respectively, through an agency relationship.  Under the terms of the asset management agreement, PSNC Energy receives storage asset management feesof which 75% are credited to rate payers. No fees are received under the supply service agreement. This agreement expires on March 31, 2017.

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Earnings Per Share

The Company computes basic earnings per share by dividing net income by the weighted average number of common shares outstanding for the period. The Company computes diluted earnings per share using this same formula, after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method. The weighted average number of common shares for each period presented for basic and diluted earnings per share purposes were identical.

Dispositions

In the first quarter of 2015, SCANA sold CGT and SCI. CGT was an interstate natural gas pipeline regulated by FERC that transported natural gas in South Carolina and southeastern Georgia, and it was sold to Dominion Resources, Inc. SCI provided fiber optic communications and other services and built, managed and leased communications towers in several southeastern states, and it was sold to a subsidiary of Spirit Communications. These sales resulted in recognition of pre-tax gains totaling approximately $342 million. As previously noted, the pre-tax gain from the sale of CGT is included within Operating Income and the pre-tax gain from the sale of SCI is included within Other Income (Expense) on the Company's condensed consolidated statement of income.

CGT and SCI operated principally in wholesale markets, whereas the Company's primary focus is the delivery of energy-related products and services to retail markets. In addition, neither CGT nor SCI met accounting criteria for disclosure as a reportable segment and were included within the All Other caption in Note 10. The sales of CGT and SCI did not represent a strategic shift that had a major effect on the Company's operations; therefore, these sales did not meet the criteria for classification as discontinued operations.

Reclassifications

Certain prior period amounts within the reconciliations of Net income to Net Cash Provided From Operating Activities on the Condensed Consolidated Statements of Cash Flows of the Company and Consolidated SCE&G have been reclassified to conform to the current period presentation. Specifically, $81 million of non-cash changes in fair value of interest rate swaps has been reclassified from the Derivative financial instruments caption, with offsetting reclassifications of $96 million and $(15) million within changes in the Regulatory assets and changes in Other liabilities captions, respectively. Additionally, due to insignificance, the captions for changes in Interest accrued and changes in Pension and other postretirement benefits which were utilized in the reconciliation for the prior period have been eliminated and their amounts included within changes in Other liabilities. These reclassifications had no effect on Net Cash Provided From Operating Activities or on any other subtotal in the Condensed Consolidated Statements of Cash Flows.

New Accounting Matters

In May 2014, the FASB issued accounting guidance for revenue arising from contracts with customers that supersedes most current revenue recognition guidance, including industry-specific guidance. This revenue recognition model provides a

five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the

transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive

in exchange for those goods or services. This guidance must be adopted no later than the first quarter of 2018, and early

adoption is permitted in the first quarter of 2017. Adoption using a retrospective method is required, with options to elect

certain practical expedients or to recognize a cumulative effect in the year of initial adoption. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what practical expedients will be elected. The Company and Consolidated SCE&G have not determined the impact this guidance will have on their respective financial statements.

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. This guidance was adopted in the first quarter of 2016 and had no impact on the Company’s or Consolidated SCE&G's financial statements.

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 and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2017. The Company and Consolidated SCE&G are evaluating this guidance and have not determined what impact it will have on their respective financial statements.

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In January 2016, the FASB issued accounting guidance intended to clarify the classification and measurement of financial instruments and financial liabilities, among other things. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018. The Company and Consolidated SCE&G are evaluating this guidance and have not determined what impact it will have on their respective financial statements.

In February 2016, the FASB issued accounting guidance related to the recognition, measurement and presentation of

leases. The guidance applies a right-of-use model and, for lessees, requires all leases with a duration over twelve months to be

recorded on the balance sheet, with the rights of use treated as assets and the payment obligations treated as liabilities. Further,

and without consideration of any regulatory accounting requirements which may apply, depending primarily of the nature of the

assets and the relative consumption of them, lease costs will be recognized either through the separate amortization of the right-of-use asset and the recognition of the interest cost related to the payment obligation, or through the recording of a combined

straight-line rental expense. For lessors, the guidance calls for the recognition of income either through the derecognition of

assets and subsequent recording of interest income on lease amounts receivable, or through the recognition of rental income on

a straight line basis, also depending on the nature of the assets and relative consumption. The guidance will be effective for

years beginning in 2019. The Company and Consolidated SCE&G have not determined what impact this guidance will have on their respective financial statements.

In March 2016, the FASB issued accounting guidance changing how companies account for certain aspects of share-based payments to employees. Entities will be required to recognize the income tax effects of awards in the income statement when the awards vest or are settled. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2017. The Company and Consolidated SCE&G are evaluating this guidance and have not determined what impact it will have on their respective financial statements.

2.RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric - Cost of Fuel

By order dated July 15, 2015, the SCPSC approved a settlement agreement among SCE&G and certain other parties concerning SCE&G's petition for approval to participate in a DER program and to recover DER program costs as a separate component of SCE&G's overall fuel factor. Under this order, SCE&G will, among other things, implement programs to encourage the development of renewable energy facilities with a total nameplate capacity of at least approximately 84.5 MW by the end of 2020, of which half is to be customer-scale solar capacity and half is to be utility-scale solar capacity. SCE&G is to make a good faith effort to have at least 30 MW of utility-scale solar capacity in service by the end of 2016.

By Order dated April 29, 2016, the SCPSC approved a settlement agreement among SCE&G, ORS and certain other parties to decrease the total fuel cost component of retail electric rates. SCE&G will reduce the total fuel cost component of retail electric rates to reflect lower projected fuel costs and to eliminate over-collected balances of approximately $61 million for base fuel and environmental costs over a 12-month period beginning with the first billing cycle of May 2016. SCE&G will also recover projected DER program costs of $6.9 million beginning with the first billing cycle of May 2016.

Electric - Base Rates

Pursuant to a 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 months ended March 31, 2016 totaled $3.1 million, and during the three months ended March 31, 2015 totaled $1.9 million. SCE&G anticipates that when the New Units are placed in service and accelerated tax depreciation is recognized on them, these deferred income tax assets will decline. When these deferred income tax assets are fully offset by related deferred income tax liabilities, the carrying cost accruals will cease, and the regulatory asset will begin to be amortized.

By Order dated April 29, 2016, the SCPSC approved SCE&G’s request to increase its pension costs component rider. This pension rider is subject to an annual true-up, depending on conditions in financial markets and other factors. The adjustment is designed to allow SCE&G to recover projected pension costs, including under-collections, over a 12-month period, beginning with the first billing cycle in May 2016.

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In April 2016, ORS filed a report arising from its review of SCE&G’s annual DSM Programs rate rider filing. ORS concluded the updated DSM Programs rider proposal was developed in accordance with terms and conditions approved by the SCPSC in prior orders and recommended that SCE&G's request be approved. In addition, ORS recommended SCE&G update the three-year planning models used to calculate the overall effectiveness of the DSM Programs for future program years. By Order dated April 29, 2016, the SCPSC accepted ORS's recommendations and approved SCE&G's request to recover $37.6 million of costs and net lost revenues associated with the DSM Programs.

Gas - PSNC Energy

On March 31, 2016, PSNC Energy filed a general rate case application with the NCUC requesting a general rate increase of approximately $41.6 million, or approximately 9.7%, in annual revenue. The rate increase is largely associated with recovering costs related to expanding and operating PSNC Energy's pipeline system. In its application, PSNC Energy is also requesting approval of a rider to its rates to track and provide for ongoing recovery of capital expenditures related to PSNC Energy’s transmission and distribution pipeline integrity management programs. A hearing on the application is scheduled for the week of August 29, 2016.

Regulatory Assets and Regulatory Liabilities

Rate-regulated utilities recognize in their financial statements certain revenues and expenses in different periods than do other enterprises.  As a result, the Company and Consolidated SCE&G have recorded regulatory assets and regulatory liabilities which are summarized in the following tables. Other than unrecovered plant, substantially all regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities.

	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2016		December 31, 2015		March 31, 2016		December 31, 2015
Regulatory Assets:
Accumulated deferred income taxes	$	297	$	298	$	290	$	291
Environmental remediation costs	41		42		34		35
AROs and related funding	402		405		381		384
Deferred employee benefit plan costs	323		325		293		295
Deferred losses on interest rate derivatives	666		535		666		535
Unrecovered plant	125		127		125		127
DSM Programs	61		61		61		61
Other	153		144		136		129
Total Regulatory Assets	$	2,068	$	1,937	$	1,986	$	1,857

Regulatory Liabilities:
Asset removal costs	$	739	$	732	$	522	$	519
Deferred gains on interest rate derivatives	81		96		81		96
Other	27		27		20		20
Total Regulatory Liabilities	$	847	$	855	$	623	$	635

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.

Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by the Company or Consolidated 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.

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Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under GAAP. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. Accordingly, in 2013 SCE&G began recovering through utility rates approximately $63 million of deferred pension costs for electric operations over approximately 30 years and approximately $14 million of deferred pension costs for gas operations over approximately 14 years. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees, or up to approximately 12 years.

Deferred losses or gains on interest rate derivatives represent (i) the effective portions of changes in fair value and payments made or received upon settlement of certain interest rate derivatives designated as cash flow hedges and (ii) the changes in fair value and payments made or received upon settlement of certain other interest rate derivatives not so designated. The amounts recorded with respect to (i) are expected to be amortized to interest expense over the lives of the underlying debt through 2043. The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense through 2065 except when, in the case of deferred gains, such amounts are applied otherwise at the direction of the SCPSC.

Unrecovered plant represents the carrying value of coal-fired generating units, including related materials and supplies inventory, retired from service prior to being fully depreciated. Pursuant to SCPSC approval, SCE&G will amortize these amounts through cost of service rates over the units' previous estimated remaining useful lives through approximately 2025. Unamortized amounts are included in rate base and are earning a current return.

DSM Programs represent SCE&G's deferred costs associated with such programs, and such deferred costs are currently being recovered over approximately five years through an approved rate rider. 

Various other regulatory assets are expected to be recovered in rates over periods of up to approximately 30 years.

Asset removal costs represent estimated net collections through depreciation rates of amounts to be incurred for the removal of assets in the future.

The SCPSC, the NCUC or the FERC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other regulatory assets include, but are not limited to, certain costs which have not been specifically approved for recovery by the SCPSC, the NCUC or by the FERC. In recording such costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders. The costs are currently not being recovered, but are expected to be recovered through rates in future periods. In the future, as a result of deregulation or other changes in the regulatory environment or changes in accounting requirements, the Company or Consolidated SCE&G could be required to write off its regulatory assets and liabilities. Such an event could have a material effect on the Company's and Consolidated SCE&G's financial statements in the period the write-off would be recorded.

3.COMMON EQUITY

SCANA had 200 million shares of common stock authorized as of March 31, 2016 and December 31, 2015. Gains and losses on cash flow hedges reclassified during the three months ended March 31, 2016 resulted in higher interest expense of $2 million and higher cost of gas purchased for resale of $5 million. Such reclassifications during the comparable period in 2015 resulted in higher interest expense of $2 million and higher cost of gas purchased for resale of $7 million.

Authorized shares of SCE&G common stock were 50 million as of March 31, 2016 and December 31, 2015. Authorized shares of SCE&G preferred stock were 20 million, of which 1,000 shares, no par value, were issued and outstanding as of March 31, 2016 and December 31, 2015. All issued and outstanding shares of SCE&G's common and preferred stock are held by SCANA.

4.     LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

Substantially all electric utility plant is pledged as collateral in connection with long-term debt.

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Liquidity

Credit agreements are used for general corporate purposes, including liquidity support for each company's commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, certain fossil fuels, and emission and other environmental allowances. Committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Committed LOC, outstanding LOC advances, commercial paper, and LOC-supported letter of credit obligations were as follows: 

	March 31, 2016
Millions of dollars	Total		SCANA			Consolidated SCE&G			PSNC  Energy
Lines of credit:
Five-year, expiring December 2020	$	1,300	$	400		$	700		$	200
Fuel Company five-year, expiring December 2020	$	500	—			$	500		—
Three-year, expiring December 2018	$	200	—			$	200		—
Total committed long-term	$	2,000	$	400		$	1,400		$	200
Outstanding commercial paper (270 or fewer days)	$	917	$	10		$	870		$	37
Weighted average interest rate			0.90		%	0.83		%	0.81		%
Letters of credit supported by LOC	$	3.3	$	3		$	0.3		—
Available	$	1,080	$	387		$	530		$	163

	December 31, 2015
Millions of dollars	Total		SCANA			Consolidated SCE&G			PSNC  Energy
Lines of credit:
Five-year, expiring December 2020	$	1,300	$	400		$	700		$	200
Fuel Company five-year, expiring December 2020	$	500	—			$	500		—
Three-year, expiring December 2018	$	200	—			$	200		—
Total committed long-term	$	2,000	$	400		$	1,400		$	200
Outstanding commercial paper (270 or fewer days)	$	531	$	37		$	420		$	74
Weighted average interest rate			1.19		%	0.74		%	0.77		%
Letters of credit supported by LOC	$	3.3	$	3		$	0.3		—
Available	$	1,466	$	360		$	980		$	126

Each of the Company and Consolidated SCE&G is obligated with respect to an aggregate of $67.8 million of industrial revenue bonds which are secured by letters of credit issued by TD Bank N.A. These letters of credit expire, subject to renewal, in the fourth quarter of 2019.

    Consolidated SCE&G participates in a utility money pool with SCANA and another regulated subsidiary of SCANA. Money pool borrowings and investments bear interest at short-term market rates. Consolidated SCE&G’s interest income and expense from money pool transactions were not significant for any period presented. At March 31, 2016, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $43.9 million. At December 31, 2015, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $33.0 million and money pool investments due from an affiliate of $9.0 million. On Consolidated SCE&G's balance sheets, amounts due from an affiliate are included within Receivables-affiliated companies, and amounts due to an affiliate are included within Affiliated payables.

5. INCOME TAXES

Consolidated SCE&G is included in the consolidated federal income tax returns of SCANA and files various applicable state and local income tax returns.

During 2013 and 2014, SCANA amended certain of its tax returns to claim certain tax-defined research and development deductions and credits and its related impact on domestic production activities. SCANA also made similar claims in filing its 2013 and 2014 returns in 2014 and 2015, respectively. In connection with these federal and state filings, the Company and Consolidated SCE&G recorded an unrecognized tax benefit of $49 million. If recognized, $17 million of the tax

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benefit would affect the Company’s and Consolidated SCE&G's effective tax rate. It is reasonably possible that these tax benefits will increase by an additional $7 million within the next 12 months. It is also reasonably possible that these tax benefits may decrease by $8 million within the next 12 months. No other material changes in the status of the Company’s or Consolidated SCE&G's tax positions have occurred through March 31, 2016.

The Company and Consolidated SCE&G recognize interest accrued related to unrecognized tax benefits within interest expense or interest income and recognize tax penalties within other expenses.  Amounts recorded for such interest income, interest expense or tax penalties have not been material.

6. DERIVATIVE FINANCIAL INSTRUMENTS

Derivative instruments are recognized either as assets or liabilities in the statement of financial position and are measured at fair value. Changes in the fair value of derivative instruments are recognized either in earnings, as a component of other comprehensive income (loss) or, for regulated operations, within regulatory assets or regulatory liabilities, depending upon the intended use of the derivative and the resulting designation. 

Policies and procedures and risk limits are established to control the level of market, credit, liquidity and operational and administrative risks.  SCANA’s Board of Directors has delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and oversee and review the risk management process and infrastructure for SCANA and each of its subsidiaries.  The Risk Management Committee, which is comprised of certain officers, including the Risk Management Officer and other senior officers, apprises the Audit Committee of the Board of Directors with regard to the management of risk and brings to their attention significant areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions.

Commodity Derivatives

The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types.  Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations. Instruments designated as fair value hedges are used to mitigate exposure to fluctuating market prices created by fixed prices of stored natural gas.  The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy companies and financial institutions.  Cash settlements of commodity derivatives are classified as operating activities in the 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

Interest rate swaps may be used to manage interest rate risk and exposure to changes in fair value attributable to changes in interest rates on certain debt issuances.  In cases where swaps that are designated as cash flow hedges are used to

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synthetically convert variable rate debt to fixed rate debt, periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense.

Treasury rate lock or forward starting swap agreements that are designated as cash flow hedges may be used in anticipation of the issuance of debt.  Except as described in the following paragraph, the effective portions of changes in fair value and payments made or received upon termination of such agreements for regulated subsidiaries are recorded in regulatory assets or regulatory liabilities. For SCANA and the nonregulated subsidiaries, such amounts are recorded in AOCI. Such amounts are amortized to interest expense over the term of the underlying debt. Ineffective portions of fair value changes are recognized in income.

Pursuant to regulatory orders, interest rate derivatives entered into by SCE&G after October 2013 are not designated as cash flow hedges and fair value changes and settlement amounts are recorded as regulatory assets and liabilities. Settlement losses on swaps will be amortized over the lives of subsequent debt issuances and gains may be applied to under-collected fuel, may be amortized to interest expense or may be applied as otherwise directed by the SCPSC.

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)
		Retail Gas
Hedge designation	Gas Distribution	Marketing	Energy Marketing	Total
As of March 31, 2016
Commodity contracts	9,240,000	6,236,000	4,632,500	20,108,500
Energy management contracts (a)	—	—	30,994,204	30,994,204
Total (a)	9,240,000	6,236,000	35,626,704	51,102,704
As of December 31, 2015
Commodity contracts	7,530,000	7,869,000	3,973,500	19,372,500
Energy management contracts (b)	—	—	38,857,480	38,857,480
Total (b)	7,530,000	7,869,000	42,830,980	58,229,980

(a)  Includes an aggregate 1,679,289 MMBTU related to basis swap contracts in Energy Marketing.

(b)  Includes an aggregate 1,842,048 MMBTU related to basis swap contracts in Energy Marketing.

The aggregate notional amounts of the interest rate swaps were as follows:

Interest Rate Swaps
	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2016		December 31, 2015		March 31, 2016		December 31, 2015
Designated as hedging instruments	$	120.0	$	120.0	$	36.4	$	36.4
Not designated as hedging instruments	1,235.0		1,235.0		1,235.0		1,235.0

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The following table shows the fair value and balance sheet location of derivative instruments. Although derivatives subject to master netting arrangements are netted on the Consolidated Balance Sheet, the fair values presented below are shown gross and cash collateral on the derivatives has not been netted against the fair values shown.

Fair Values of Derivative Instruments
		The Company				Consolidated SCE&G
Millions of dollars	Balance Sheet Location	Asset		Liability		Asset		Liability
As of March 31, 2016
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	3			$	1
	Other deferred credits and other liabilities			36				12
Commodity contracts
	Other current assets	$	1	1
	Derivative financial instruments			2
Total		$	1	$	42	—		$	13
Not designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	100			$	100
	Other deferred credits and other liabilities			83				83
Commodity contracts
	Other current assets	$	2
Energy management contracts
	Other current assets	9		1
	Other deferred debits and other assets	4
	Derivative financial instruments			9
	Other deferred credits and other liabilities			3
Total		$	15	$	196	—		$	183
As of December 31, 2015
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	4			$	1
	Other deferred credits and other liabilities			28				9
Commodity contracts
	Other current assets			1
	Derivative financial instruments			4
Total		$	—	$	37	—		$	10
Not designated as hedging instruments
Interest rate contracts
	Other current assets	$	10			$	10
	Other deferred debits and other assets	5				5
	Derivative financial instruments			$	33			$	33
	Other deferred credits and other liabilities			22				22
Commodity contracts
	Other current assets	1		2
Energy management contracts
	Other current assets	11
	Other deferred debits and other assets	3
	Derivative financial instruments			9
	Other deferred credits and other liabilities			3
Total		$	30	$	69	$	15	$	55

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 The effect of derivative instruments on the condensed consolidated statements of income is as follows: 

Derivatives in Cash Flow Hedging Relationships

The Company and Consolidated SCE&G:
	Loss Deferred in Regulatory Accounts							Loss Reclassified from Deferred Accounts into Income
	(Effective Portion)							(Effective Portion)
Millions of dollars	2016			2015			Location	2016			2015
Three Months Ended March 31,
Interest rate contracts	$	(3	)	$	(2	)	Interest expense	$	(1	)	$	—

The Company:
	Loss Recognized in OCI, net of tax							Loss Reclassified from AOCI into Income, net of tax
	(Effective Portion)							(Effective Portion)
Millions of dollars	2016			2015			Location	2016			2015
Three Months Ended March 31,
Interest rate contracts	$	(3	)	$	(2	)	Interest expense	$	(2	)	$	(2	)
Commodity contracts	(2		)	(1		)	Gas purchased for resale	(5		)	(7		)
Total	$	(5	)	$	(3	)		$	(7	)	$	(9	)

As of March 31, 2016, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $1.1 million as an increase to gas cost, assuming natural gas markets remain at their current levels, and approximately $6.5 million as an increase to interest expense.  As of March 31, 2016, all of the Company’s commodity cash flow hedges settle by their terms before the end of the first quarter of 2019.

As of March 31, 2016, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $2.1 million as an increase to interest expense.

Hedge Ineffectiveness

For the Company and Consolidated SCE&G, ineffectiveness on interest rate hedges designated as cash flow hedges was insignificant during all periods presented.

Derivatives not designated as Hedging Instruments
The Company and Consolidated SCE&G:
	Loss Deferred in Regulatory Accounts							Gain Reclassified from Deferred Accounts into Income
Millions of dollars	2016			2015			Location	2016		2015
Three Months Ended March 31,
Interest rate contracts	$	(144	)	$	(94	)	Other income	$	—	$	4

As of March 31, 2016, the Company and Consolidated SCE&G expect that during the next 12 months reclassifications from regulatory accounts to earnings arising from derivatives not designated as hedges will include $0.7 million as an increase to interest expense.

Credit Risk Considerations

Certain derivative contracts contain contingent credit features. These features may include (i) material adverse change clauses or payment acceleration clauses that could result in immediate payments or (ii) the posting of letters of credit or

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termination of the derivative contract before maturity if specific events occur, such as a credit rating downgrade below investment grade or failure to post collateral.

Derivative Contracts with Credit Contingent Features
	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2016		December 31, 2015		March 31, 2016		December 31, 2015
in Net Liability Position
Aggregate fair value of derivatives in net liability position	$	234.1	$	95.2	$	196.1	$	57.0
Fair value of collateral already posted	124.1		50.4		88.2		13.4
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	110.0		44.8		107.9		43.6
in Net Asset Position
Aggregate fair value of derivatives in net asset position	$	—	$	7.3	$	—	$	7.3
Fair value of collateral already posted	—		—		—		—
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	—		7.3		—		7.3

In addition, for fixed price supply contracts offered to certain of SEMI's customers, the Company could have called on letters of credit in the amount of $3.0 million related to $13.0 million in commodity derivatives that are in a net asset position at March 31, 2016, compared to letters of credit of $3.0 million related to derivatives of $14.0 million at December 31, 2015, if all the contingent features underlying these instruments had been fully triggered.

Information related to the offsetting of derivative assets follows:

Derivative Assets	The Company												Consolidated SCE&G
Millions of dollars	Interest Rate Contracts			Commodity Contracts			Energy Management Contracts			Total			Interest Rate Contracts
As of March 31, 2016
Gross Amounts of Recognized Assets	—			$	3		$	13		$	16		—
Gross Amounts Offset in Statement of Financial Position	—			(1		)	—			(1		)	—
Net Amounts Presented in Statement of Financial Position	—			2			13			15			—
Gross Amounts Not Offset - Financial Instruments	—			—			—			—			—
Gross Amounts Not Offset - Cash Collateral Received	—			—			—			—			—
Net Amount	—			$	2		$	13		$	15		—
Balance sheet location
Other current assets										$	11		—
Other deferred debits and other assets										4			—
Total										$	15		—
As of December 31, 2015
Gross Amounts of Recognized Assets	$	15		$	1		$	15		$	31		$	15
Gross Amounts Offset in Statement of Financial Position	—			—			(1		)	(1		)	—
Net Amounts Presented in Statement of Financial Position	15			1			14			30			15
Gross Amounts Not Offset - Financial Instruments	(8		)	—			—			(8		)	(8		)
Gross Amounts Not Offset - Cash Collateral Received	—			—			—			—			—
Net Amount	$	7		$	1		$	14		$	22		$	7
Balance sheet location
Other current assets										$	22		$	10
Other deferred debits and other assets										8			5
Total										$	30		$	15

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Information related to the offsetting of derivative liabilities follows:

Derivative Liabilities	The Company												Consolidated SCE&G
Millions of dollars	Interest Rate Contracts			Commodity Contracts			Energy Management Contracts			Total			Interest Rate Contracts
As of March 31, 2016
Gross Amounts of Recognized Liabilities	$	222		$	3		$	13		$	238		$	196
Gross Amounts Offset in Statement of Financial Position	—			(1		)	—			(1		)	—
Net Amounts Presented in Statement of Financial Position	222			2			13			237			196
Gross Amounts Not Offset - Financial Instruments	—			—			—			—			—
Gross Amounts Not Offset - Cash Collateral Posted	(116		)	(2		)	(6		)	(124		)	(88		)
Net Amount	$	106		$	—		$	7		$	113		$	108
Balance sheet location
Other current assets										$	2		—
Derivative financial instruments										113			$	101
Other deferred credits and other liabilities										122			95
Total										$	237		$	196
As of December 31, 2015
Gross Amounts of Recognized Liabilities	$	87		$	5		$	15		$	107		$	65
Gross Amounts Offset in Statement of Financial Position	—			—			(1		)	(1		)	—
Net Amounts Presented in Statement of Financial Position	87			5			14			106			65
Gross Amounts Not Offset - Financial Instruments	(8		)	—			—			(8		)	(8		)
Gross Amounts Not Offset - Cash Collateral Posted	(36		)	(5		)	(9		)	(50		)	(13		)
Net Amount	$	43		$	—		$	5		$	48		$	44
Balance sheet location
Other current assets										$	3		—
Derivative financial instruments										50			$	34
Other deferred credits and other liabilities										53			31
Total										$	106		$	65

7. FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

The Company values available for sale securities using quoted prices from a national stock exchange, such as the NASDAQ, where the securities are actively traded. For commodity derivative and energy management assets and liabilities, the Company uses unadjusted NYMEX prices to determine fair value, and considers such measures of fair value to be Level 1 for exchange traded instruments and Level 2 for over-the-counter instruments. The Company’s and Consolidated SCE&G's interest rate swap agreements are valued using discounted cash flow models with independently sourced data. Fair value measurements, and the level within the fair value hierarchyin which the measurements fall, were as follows:

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	As of March 31, 2016						As of December 31, 2015
	The Company				Consolidated SCE&G		The Company				Consolidated SCE&G
Millions of dollars	Level 1		Level 2		Level 2		Level 1		Level 2		Level 2
Assets:
Available for sale securities	$	11					$	11
Held to maturity securities			$	7
Interest rate contracts									$	15	$	15
Commodity contracts	2						1
Energy management contracts			13						14
Liabilities:
Interest rate contracts			222		$	196			87		65
Commodity contracts			2				1		4
Energy management contracts	1		13				4		12

The Company had no Level 3 fair value measurements for either period presented, and there were no transfers of fair value amounts into or out of Levels 1, 2 or 3 during the periods presented. Consolidated SCE&G had 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:

Long-Term Debt	March 31, 2016				December 31, 2015
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
The Company	$	5,995.4	$	6,704.5	$	5,997.6	$	6,445.7
Consolidated SCE&G	$	4,766.9	$	5,368.3	$	4,769.0	$	5,129.1

Fair values of long-term debt instruments are based on net present value calculations using independently sourced market data that incorporate a developed discount rate using similarly rated long-term debt, along with benchmark interest rates.  As such, the aggregate fair values presented above are considered to be Level 2. Early settlement of long-term debt may not be possible or may not be considered prudent.

Carrying values of short-term borrowings approximate 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.

8. EMPLOYEE BENEFIT PLANS

Components of net periodic benefit cost recorded by the Company and Consolidated SCE&G were as follows: 

The Company	Pension Benefits						Other Postretirement Benefits
	2016			2015			2016		2015
Three months ended March 31,
Service cost	$	5.5		$	5.8		$	1.3	$	1.4
Interest cost	9.9			9.5			3.0		2.9
Expected return on assets	(14.1		)	(15.5		)	—		—
Prior service cost amortization	1.0			1.0			0.1		0.1
Amortization of actuarial losses	3.7			3.5			0.1		0.6
Net periodic benefit cost	$	6.0		$	4.3		$	4.5	$	5.0

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Consolidated SCE&G	Pension Benefits						Other Postretirement Benefits
	2016			2015			2016		2015
Three months ended March 31,
Service cost	$	4.5		$	4.6		$	1.0	$	1.1
Interest cost	8.4			8.0			2.5		2.3
Expected return on assets	(11.9		)	(13.0		)	—		—
Prior service cost amortization	0.8			0.8			0.1		0.1
Amortization of actuarial losses	3.1			3.0			0.1		0.4
Net periodic benefit cost	$	4.9		$	3.4		$	3.7	$	3.9

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.

9. 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 $13.4 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $375 million by ANI with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. Each reactor licensee is currently liable for up to $127.3 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $18.9 million of the liability per reactor would be assessed per year. SCE&G’s maximum assessment, based on its two-thirds ownership of Summer Station Unit 1, would be $84.8 million per incident, but not more than $12.6 million per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years.

SCE&G currently maintains insurance policies (for itself and on behalf of Santee Cooper) with NEIL. The policies provide coverage to Summer Station Unit 1 for property damage and outage costs up to $2.75 billion resulting from an event of nuclear origin and up to $2.25 billion resulting from an event of a non-nuclear origin. In addition, a builder's risk insurance policy has been purchased from NEIL for the construction of the New Units. This policy provides the owners of the New Units up to $500 million of total coverage for accidental property damage occurring during construction. The NEIL policies, in the aggregate, are subject to a maximum loss of $2.75 billion for any single loss occurrence. All of the NEIL policies permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $43.5 million. SCE&G currently maintains an excess property insurance policy (for itself and on behalf of Santee Cooper) with EMANI. The policy provides coverage to Summer Station Unit 1 for property damage and outage costs up to $415 million resulting from an event of a non-nuclear origin. The EMANI policy permits retrospective assessments under certain conditions to cover insurer's losses. Based on the current annual premium, SCE&G's portion of the retrospective premium assessment would not exceed $1.8 million.

To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from an incident at 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 or other incident. However, if such an incident were to occur, it likely would have a material impact on the Company’s and Consolidated SCE&G's results of operations, cash flows and financial position.

New Nuclear Construction

In 2008, SCE&G, on behalf of itself and as agent for Santee Cooper, contracted with the Consortium for the design and construction of the New Units at the site of Summer Station. SCE&G's current ownership share in the New Units is 55%. As discussed below, SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper.

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EPC Contract and BLRA Matters

The construction of the New Units and SCE&G’s related recovery of financing costs through rates is subject to review and approval by the SCPSC as provided for in the BLRA. Under the BLRA, the SCPSC has approved, among other things, a milestone schedule and a capital costs estimates schedule for the New Units. This approval constitutes a final and binding determination that the New Units are used and useful for utility purposes, and that the capital costs associated with the New Units are prudent utility costs and expenses and are properly included in rates, so long as the New Units are constructed or are being constructed within the parameters of the approved milestone schedule, including specified contingencies, and the approved capital costs estimates schedule. Subject to the same conditions, the BLRA provides that SCE&G may apply to the SCPSC annually for an order to recover through revised rates SCE&G’s weighted average cost of capital applied to all or part of the outstanding balance of construction work in progress concerning the New Units. As of March 31, 2016, SCE&G’s investment in the New Units, including related transmission, totaled $3.8 billion, for which the financing costs on $3.2 billion have been reflected in rates under the BLRA.

The SCPSC granted initial approval of the construction schedule and related forecasted capital costs in 2009. The NRC issued COLs in March 2012. In November 2012, the SCPSC approved an updated milestone schedule and additional updated capital costs for the New Units. In addition, the SCPSC approved revised substantial completion dates for the New Units based on that March 2012 issuance of the COL and the amounts agreed upon by SCE&G and the Consortium in July 2012 to resolve known claims by the Consortium for costs related to COL delays, design modifications of the shield building and certain prefabricated structural modules for the New Units and unanticipated rock conditions at the site. In October 2014, the South Carolina Supreme Court affirmed the SCPSC's order on appeal.

Since the settlement of delay-related claims in 2012, the Consortium has continued to experience delays in the schedule. Shield building construction remains a principal focus area for SCE&G’s oversight of the project. The primary critical path for both Unit 2 and Unit 3 runs through the fabrication of shield building components and the completion of shield building construction. For Unit 3, the critical path also runs through the setting of Containment Vessel Ring 1 and placement of concrete in certain areas of the nuclear island to form a foundation for the shield building. Plans to accelerate the work needed to permit placing this concrete are underway. In addition, WEC has reached agreement on a mitigation plan to accelerate shield building panel fabrication with one of its subcontractors. Additional mitigation will be required in critical path areas to support the updated substantial completion dates described below.

During the fourth quarter of 2013, the Consortium began a full re-baselining of the Unit 2 and Unit 3 construction schedules to incorporate a more detailed evaluation of the engineering and procurement activities necessary to accomplish the schedules and to provide a detailed reassessment of the impact of the revised Unit 2 and Unit 3 schedules on engineering and design resource allocations, procurement, construction work crew efficiencies and other items. The result was a revised fully integrated project schedule with timing of specific construction activities (Revised, Fully-Integrated Construction Schedule) along with related cost information.

The Revised, Fully-Integrated Construction Schedule indicated that the substantial completion of Unit 2 was expected to occur in June 2019 and that the substantial completion of Unit 3 was expected to be approximately 12 months later. The Consortium continues to refine and update the Revised, Fully-Integrated Construction Schedule as designs are finalized, as construction progresses, and as additional information is received.

In September 2015, the SCPSC approved an updated BLRA milestone schedule based on revised substantial completion dates for Units 2 and 3 of June 2019 and June 2020, respectively, each subject to an 18-month contingency period. In addition, the SCPSC approved certain updated owner's costs ($245 million) and other capital costs ($453 million), of which $539 million were associated with the schedule delays and other contested costs. In this proceeding, SCE&G's total projected capital costs (in 2007 dollars) and gross construction cost estimates (including escalation and AFC) were estimated to be $5.2 billion and $6.8 billion, respectively. These projections included cost amounts related to the Revised, Fully-Integrated Construction Schedule for which SCE&G had not accepted responsibility and which were the subject of dispute. As such, the updated milestone schedule and projections did not reflect the resolution of negotiations. In addition, the SCPSC approved a revision to the allowed return on equity for new nuclear construction from 11.0% to 10.5%. This revised return on equity will be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2016, until such time as the New Units are completed.

On October 27, 2015, SCE&G, Santee Cooper and the Consortium reached a settlement regarding the above mentioned disputes, and the EPC Contract was amended. The October 2015 Amendment became effective in December 2015, upon the consummation of the acquisition by WEC of the stock of Stone & Webster from CB&I. Following that acquisition,

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Stone & Webster continues to be a member of the Consortium as a subsidiary of WEC rather than CB&I, and WEC has engaged Fluor Corporation as a subcontracted construction manager.

Among other things, the October 2015 Amendment:

(i) resolved by settlement and release most outstanding disputes between SCE&G and the Consortium, in exchange for (a) an additional cost to be paid by SCE&G and Santee Cooper of $300 million (SCE&G’s 55% portion being $165 million and an increase in the fixed component of the contract price by that amount, and (b) a credit to SCE&G and Santee Cooper of $50 million (SCE&G’s 55% portion being approximately $27 million) to be applied to the target component of the contract price,

(ii) revised the guaranteed substantial completion dates of Units 2 and 3 to August 31, 2019 and 2020, respectively,

(iii) revised the delay-related liquidated damages computation requirements, including those related to the eligibility of the New Units to earn Internal Revenue Code Section 45J production tax credits (see also below), and capped those aggregate liquidated damages at $463 million per New Unit (SCE&G’s 55% portion being approximately $255 million per New Unit),

(iv) provides for payment to the Consortium of a completion bonus of $275 million per New Unit (SCE&G’s 55% portion being approximately $151 million per New Unit) for each New Unit placed in service by the deadline to qualify for production tax credits,

(v) provides for development of a revised construction milestone payment schedule, with SCE&G and Santee Cooper making monthly payments of $100 million (SCE&G’s 55% portion being $55 million) for each of the first five months following effectiveness, followed by payments made based on milestones achieved, and

(vi) provided that SCE&G and Santee Cooper waive and cancel the CB&I parent company guaranty with respect to the project.

Under the October 2015 Amendment, SCE&G’s total estimated project costs increased by approximately $286 million over the $6.8 billion approved by the SCPSC in September 2015. In addition, SCE&G has updated project costs for estimated change orders related to certain outstanding disputes not resolved by the October 2015 Amendment. As of April 30, 2016, these estimated change orders total approximately $53 million. The estimated gross construction cost of the project (including the effects of these change orders, escalation and AFC) as of March 31, 2016 totals approximately $7.2 billion.

As of March 31, 2016, payments related to (i) above had been made totaling $62.5 million (SCE&G's 55% portion being approximately $34.4 million), and payments related to (v) above had been made totaling $300 million (SCE&G's 55% portion being $165 million).

Payment and performance obligations under the EPC Contract are joint and several obligations of WEC and Stone & Webster, and in connection with the October 2015 Amendment, Toshiba Corporation, WEC’s parent company, reaffirmed its guaranty of WEC’s payment obligations. Additionally, the EPC Contract provides the Owners the right, exercisable upon certain conditions, to obtain payment and performance bonds from WEC equal to 15%of the highest three months billings during the applicable year, and their aggregate nominal coverage will not exceed $100 million (or $55 millionfor SCE&G's 55% share). SCE&G and Santee Cooper are responsible for the cost of the bonds.

In late 2015, Toshiba's credit ratings declined to below investment grade following disclosures regarding its operating and financial performance and near-term liquidity. As a result, pursuant to the above-described terms of the EPC Contract, SCE&G has obtained payment and performance bonds from WEC in the form of standby letters of credit totaling $45 million(or approximately $25 millionfor SCE&G's 55% share). These standby letters of credit expire annually and automatically renew for successive one-year periods until their final expiration date of August 31, 2020, unless the issuer provides a minimum 60-day notice that it will not renew. In the event that WEC would be unable to meet its payment and performance obligations under the EPC Contract, it is anticipated this funding would provide a source of liquidity to assist in an orderly transition and in enabling construction activities to continue. In addition, the EPC Contract provides that upon the request of SCE&G, the Consortium must escrow certain intellectual property and software for SCE&G's benefit to enable completion of the New Units. An escrow arrangement and a schedule for deposit of intellectual property and software are being developed. While there have been no indications to date that WEC will not meet its obligations under the EPC Contract, SCE&G cannot predict the outcome of these matters, and continues to monitor developments for potential impacts to both the construction schedule and costs.

In addition to the above, the October 2015 Amendment provided for an explicit definition of a Change in Law designed to reduce the likelihood of certain future commercial disputes, and the Consortium also acknowledged and agreed that the project scope includes providing New Units that meet the standards of the NRC approved Design Control Document

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Revision 19. The October 2015 Amendment also established a dispute resolution board process for certain commercial claims and disputes, including any dispute that might arise with respect to the development of the revised construction milestone payment schedule referred to above. The EPC Contract was also revised to eliminate the requirement or ability to bring suit before substantial completion of the project.

Finally, the October 2015 Amendment provides SCE&G and Santee Cooper an irrevocable option, until November 1, 2016 and subject to regulatory approvals, to further amend the EPC Contract to fix the total amount to be paid to the Consortium for its entire scope of work on the project (excluding a limited amount of work within the time and materials component of the contract price) after June 30, 2015 at $6.082 billion (SCE&G’s 55% portion being approximately $3.345 billion). This total amount to be paid would be subject to adjustment for amounts paid since June 30, 2015. Were this fixed price option to be exercised, the aggregate delay-related liquidated damages referred to in (iii) above would be capped at $338 million per unit (SCE&G’s 55% portion being approximately $186 million per unit), and the completion bonus referred to in (iv) above would be $150 million per New Unit (SCE&G’s 55% portion being approximately $83 million per New Unit). The exercise of this fixed price option would result in SCE&G’s total estimated project costs increasing by approximately $774 million over the $6.8 billion approved by the SCPSC in September 2015. This increase does not include the estimated change orders described previously totaling approximately $53 million and additional sales tax that would be due under this fixed price option of approximately $10 million. The estimated gross construction cost of the project (including the effects of these change orders and additional sales tax, escalation and AFC) under this fixed price option would total approximately $7.7 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 in September 2015; however, the guaranteed substantial completion dates fall within the SCPSC approved 18-month contingency periods. SCE&G held an allowable ex parte communication briefing with the SCPSC on November 19, 2015 and, following an evaluation as to whether to exercise the fixed price option, expects to file a petition in the second quarter of 2016, as provided under the BLRA, for an update to the project’s estimated capital cost and milestone schedule which incorporates the impact of the October 2015 Amendment. Such update would also incorporate any cost or schedule changes identified since that time.

Additional claims by the Consortium or SCE&G involving the project schedule and budget may arise as the project continues. The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve such issues. SCE&G expects to resolve all disputes through both the informal and formal procedures and currently anticipates that any costs that arise through such dispute resolution processes (including those reflected in the October 2015 Amendment described above), as well as other costs identified from time to time, will be recoverable through rates.

Santee Cooper Matters

As noted above, SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper. Under the terms of this agreement, SCE&G will acquire a 1% ownership interest in the New Units at the commercial operation date of Unit 2, an additional 2% ownership interest no later than the first anniversary of such commercial operation date, and the final 2% no later than the second anniversary of such commercial operation date. SCE&G has agreed to pay an amount equal to Santee Cooper's actual cost, including its cost of financing, of the percentage conveyed as of the date of each conveyance. In addition, the agreement provides that Santee Cooper will not transfer any of its remaining interest in the New Units to third parties until the New Units are complete. This transaction will not affect the payment obligations between the parties during construction for the New Units, nor is it anticipated that the payments for the additional ownership interest would be reflected in a revised rates filing under the BLRA. Based on the October 2015 Amendment, which has not been approved by the SCPSC, SCE&G’s currently projected cost would be approximately $750 million to $850 million for the additional 5% interest being acquired from Santee Cooper.

Nuclear Production Tax Credits

The IRS has notified SCE&G that, subject to a national megawatt capacity limitation, the electricity to be produced by each of the New Units (advanced nuclear units, as defined) would qualify for nuclear production tax credits under Section 45J of the Internal Revenue Code to the extent that such New Unit is operational before January 1, 2021 and other eligibility requirements are met. These nuclear production tax credits (related to SCE&G's 55% share of both New Units) could total as much as approximately $1.4 billion. Such credits would be earned over the first eight years of each New Unit's operations and would be realized by SCE&G over those years or during allowable carry-forward periods. Based on the guaranteed substantial completion dates provided above, both New Units are expected to be operational and to qualify for the nuclear production tax credits; however, further delays in the schedule or changes in tax law could impact such conclusions. When and to the extent that production tax credits are realized, their benefits are expected to be provided directly to SCE&G's electric customers.

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Other Project Matters

When the NRC issued the COLs for the New Units, two of the conditions that it imposed were requiring inspection and testing of certain components of the New Units' passive cooling system, and requiring the development of strategies to respond to extreme natural events resulting in the loss of power at the New Units. In addition, the NRC directed the Office of New Reactors to issue to SCE&G an order requiring enhanced, reliable spent fuel pool instrumentation. SCE&G prepared and submitted an overall integration plan for the New Units to the NRC in August 2013. That plan is currently under review by the NRC and SCE&G does not anticipate any additional regulatory actions as a result of that review, but it cannot predict future regulatory activities or how such initiatives would impact construction or operation of the New Units.

Environmental

On August 3, 2015, the EPA issued its final rule on emission guidelines for states to follow in developing plans to address GHG emissions from existing units. The rule includes state-specific goals for reducing national carbon dioxide emissions by 32% from 2005 levels by 2030. The rule also provides for nuclear reactors under construction, such as the New Units, to count towards compliance and establishes a phased-in compliance approach beginning in 2022. The rule gives states from one to three years to issue SIPs, which will ultimately define the specific compliance methodology that will be applied to existing units in that state. On February 9, 2016, the Supreme Court stayed the rule pending disposition of a petition of review of the rule in the Court of Appeals. The order of the Supreme Court has no immediate impact on SCE&G and GENCO or their generation operations. The Company and Consolidated SCE&G are currently evaluating the rule and expect any costs incurred to comply with such rule to be recoverable through rates.

In July 2011, the EPA issued the CSAPR to reduce emissions of sulfur dioxide and nitrogen oxide from power plants in the eastern half of the United States. A series of court actions stayed this rule until October 23, 2014, when the Court of Appeals granted a motion to lift the stay. On December 3, 2014, the EPA published an interim final rule that aligns the dates in the CSAPR text with the revised court-ordered schedule, which delayed the implementation dates to 2015 for Phase 1 and to 2017 for Phase 2. The CSAPR replaces the CAIR and requires a total of 28 states to reduce annual sulfur dioxide emissions and annual and 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 costs incurred to comply with CSAPR are expected to be recoverable through rates.

In April 2012, the EPA's MATS rule containing new standards for mercury and other specified air pollutants became effective. The Company's and Consolidated SCE&G's decision to retire certain coal-fired units and its project to build the New Units along with other actions are expected to result in the Company's and Consolidated SCE&G's compliance with MATS.

On November 19, 2014, the EPA finalized its reconsideration of certain provisions applicable during startup and shutdown of generating facilities under the MATS rule. SCE&G and GENCO were granted a one year extension (through April 2016) to comply with MATS at Cope, McMeekin, Wateree and Williams Stations. These extensions allowed time to convert McMeekin Station to burn natural gas and to install additional pollution control devices at the other plants to enhance the control of certain MATS-regulated pollutants. On June 29, 2015, the Supreme Court ruled that the EPA unreasonably failed to consider costs in its decision to regulate. In December 2015, the Court of Appeals ruled that the MATS rule would remain in effect while the EPA assesses the cost of the rule. These rulings are not expected to have an impact on SCE&G or GENCO due to the aforementioned retirements and conversions. SCE&G and GENCO currently are in compliance with the MATS rule and expect to remain in compliance.

The CWA provides for the imposition of effluent limitations that require treatment for wastewater discharges. Under the CWA, compliance with applicable limitations is achieved under state-issued NPDES permits. As a facility’s NPDES permit is renewed (every five years), any new effluent limitations would be incorporated. The ELG Rule became effective on January 4, 2016. After this date, state regulators will modify facility NPDES permits to match more restrictive standards, thus requiring facilities to retrofit with new wastewater treatment technologies. Compliance dates will vary by type of wastewater, and some will be based on a facility's five year permit cycle and thus may range from 2018 to 2023. The Company and Consolidated SCE&G expect 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.

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The CWA Section 316(b) Existing Facilities Rule became effective in October 2014. This rule establishes national requirements for the location, design, construction and capacity of cooling water intake structures at existing facilities that reflect the best technology available for minimizing the adverse environmental impacts of impingement and entrainment. SCE&G and GENCO are conducting studies and implementing plans as required by the rule to determine appropriate intake structure modifications to ensure compliance with this rule. Any costs incurred to comply with this rule are expected to be recoverable through rates. 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.

The EPA's final rule for CCR became effective in the fourth quarter of 2015. This rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act and imposes certain requirements on ash storage ponds and other CCR management facilities at SCE&G's and GENCO's coal-fired generating facilities. SCE&G and GENCO have already closed or have begun the process of closure of all of their ash storage ponds and have previously recognized AROs for such ash storage ponds under existing requirements. The Company and Consolidated SCE&G do not expect the incremental compliance costs associated with this rule to be significant and expect to recover such costs in future rates.

The Nuclear Waste Act required that the United States government accept and permanently dispose of high-level radioactive waste and spent nuclear fuel by January 31, 1998, and it imposed on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. SCE&G entered into a Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with the DOE in 1983. As of December 31, 2015, the federal government has not accepted any spent fuel from Summer Station Unit 1, and it remains unclear when the repository may become available. SCE&G has on-site spent nuclear fuel storage capability in its existing fuel pool until at least 2017 and has constructed an independent spent fuel storage installation 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.

SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC and the EPA. SCE&G anticipates that major remediation activities at all these sites will continue at least through 2017 and will cost an additional $18.4 million, which is accrued in Other within Deferred Credits and Other Liabilities on the consolidated balance sheet. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates. At March 31, 2016, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $34.4 million and are included in regulatory assets.

10. SEGMENT OF BUSINESS INFORMATION

Regulated operations measure profitability using operating income; therefore, net income is not allocated to the Electric Operations and Gas Distribution segments. Marketing segments measure profitability using net income.

The Company's Gas Distribution segment is comprised of the local distribution operations of SCE&G and PSNC Energy which meet the criteria for aggregation. All Other includes the parent company, a services company and other nonreportable segments that were insignificant for all periods presented. In addition, All Other includes gains from the sales of CGT and SCI (see Dispositions in Note 1) and their operating results and assets prior to their sale in the first quarter of 2015. CGT and SCI were nonreportable segments during all periods presented. For the period ended March 31, 2015, operating income and net income for All Other include $235 million million and $202 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 either period presented.

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The Company
Millions of dollars	External Revenue		Intersegment Revenue			Operating Income		Net Income
Three Months Ended March 31, 2016
Electric Operations	$	592	$	1		$	198	n/a
Gas Distribution	299		1			94		n/a
Retail Gas Marketing	171		—			n/a		$	22
Energy Marketing	110		22			n/a		2
All Other	—		98			—		—
Adjustments/Eliminations	—		(122		)	39		152
Consolidated Total	$	1,172	$	—		$	331	$	176

Three Months Ended March 31, 2015
Electric Operations	$	629		—			$	199	n/a
Gas Distribution	368			—			96		n/a
Retail Gas Marketing	204			—			n/a		$	27
Energy Marketing	187			$	35		n/a		6
All Other	4			114			238		207
Adjustments/Eliminations	(3		)	(149		)	53		160
Consolidated Total	$	1,389		$	—		$	586	$	400

Consolidated SCE&G
Millions of dollars	External Revenue		Operating Income		Earnings Available to Common Shareholder
Three Months Ended March 31, 2016
Electric Operations	$	593	$	198	n/a
Gas Distributions	124		38		n/a
Adjustments/Eliminations	—		—		$	113
Consolidated Total	$	717	$	236	$	113

Three Months Ended March 31, 2015
Electric Operations	$	630	$	199	n/a
Gas Distributions	142		38		n/a
Adjustments/Eliminations	—		—		$	122
Consolidated Total	$	772	$	237	$	122

Segment Assets	The Company				Consolidated SCE&G
	March 31,		December 31,		March 31,		December 31,
Millions of dollars	2016		2015		2016		2015
Electric Operations	$	11,039	$	10,883	$	11,039	$	10,883
Gas Distribution	2,676		2,606		768		757
Retail Gas Marketing	140		106		n/a		n/a
Energy Marketing	84		95		n/a		n/a
All Other	994		998		n/a		n/a
Adjustments/Eliminations	2,435		2,458		3,125		3,125
Consolidated Total	$	17,368	$	17,146	$	14,932	$	14,765

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11.    AFFILIATED TRANSACTIONS

The Company and Consolidated SCE&G:

SCE&G owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and sale of refined coal to reduce emissions. SCE&G accounts for this investment using the equity method.  SCE&G’s total purchases from this affiliate were $52.8 million and $70.1 million for the three months ended March 31, 2016 and 2015, respectively.  SCE&G’s total sales to this affiliate were $52.5 million and $69.7 million for the three months ended March 31, 2016 and 2015, respectively. SCE&G’s receivable from this affiliate was $15.2 million at March 31, 2016 and $12.8 million at December 31, 2015.  SCE&G’s payable to this affiliate was $15.3 million at March 31, 2016 and $12.9 million at December 31, 2015.

Consolidated SCE&G:

Prior to January 31, 2015, CGT was a wholly-owned subsidiary of SCANA and transported natural gas to SCE&G to serve retail gas customers and certain electric generation requirements. SCE&G's purchases from CGT totaled approximately $3.4 million in January 2015.

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 $22.4 million and $34.6 million for the three months ended March 31, 2016 and 2015, respectively.  SCE&G’s payables to SEMI for such purchases were $4.0 million at March 31, 2016 and $7.5 million at December 31, 2015.

SCANA Services, Inc., on behalf of itself and its parent company, provides the following services to Consolidated SCE&G, which are rendered at direct or allocated cost: information systems 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 $75.6 million and $73.1 million for the three months ended March 31, 2016 and 2015, respectively. Consolidated SCE&G's payables to SCANA Services for these services were $48.1 million at March 31, 2016 and $57 million at December 31, 2015.

Consolidated SCE&G's money pool borrowings from an affiliate are described in Note 4.

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ITEM 2.     MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS

OF OPERATIONS

SCANA CORPORATION

The following discussion should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations appearing in SCANA’s Annual Report on Form 10-K for the year ended December 31, 2015.

RESULTS OF OPERATIONS

FOR THE THREE MONTHS ENDED MARCH 31, 2016

AS COMPARED TO THE CORRESPONDING PERIOD IN 2015

Earnings Per Share

The Company reports earnings as determined in accordance with GAAP. Management believes that, in addition to reported earnings under GAAP, the Company's GAAP-adjusted weather-normalized earnings per share provide a meaningful representation of its fundamental earnings power and can aid in performing period-over-period financial analysis and comparison with peer group data. In management's opinion, in addition to operating income for regulated businesses, GAAP-adjusted weather-normalized net earnings (and earnings per share) are a useful indicator of the financial results of the Company's primary businesses. These measures are also a basis for management's provision of earnings guidance and growth projections and are used in part by management in making budgetary and operational decisions including determining eligibility for certain incentive compensation payments. These non-GAAP performance measures are not intended to replace the GAAP measures of net earnings (or earnings per share), but are offered as supplements to it. A reconciliation of GAAP earnings per share to GAAP-adjusted weather-normalized net earnings per share follows:

	2016			2015
GAAP earnings per share	$	1.23		$	2.80
Remove:
Gain on sale of CGT	—			0.95
Gain on sale of SCI	—			0.46
SCE&G Electric - effect of favorable/(unfavorable) abnormal weather	(0.05		)	0.05
GAAP-adjusted weather-normalized earnings per share	$	1.28		$	1.34

Earnings per share on a GAAP basis decreased primarily due to the sales of CGT and SCI in the first quarter of 2015, and lower energy marketing earnings, higher operation and maintenance expenses, higher property taxes, lower other income and higher interest cost in the first quarter of 2016. These decreases were partially offset by higher electric and gas distribution margins, lower depreciation expense and lower income taxes, as further discussed below.

Discussion of above adjustments:

The sales of CGT and SCI were closed in the first quarter of 2015. These subsidiaries operated principally in wholesale markets, whereas the Company's primary focus is the delivery of energy-related products and services to retail markets. Therefore, CGT and SCI were not a part of the Company's core business. See Note 10 to the combined notes to condensed consolidated financial statements.

SCE&G estimates the effects on its electric business of actual temperatures in its service territory as compared to historical averages. The result is used in developing an estimate of electric margin revenue, using average margin rates, attributable to the effects of abnormal weather. During the first quarter of 2016, weather was abnormally mild; during the first quarter of 2015, weather was abnormally cold.

Management believes the above adjustments are appropriate in determining the non-GAAP financial performance measures. Such non-GAAP measures reflect management's determination that wholesale gas transportation and telecommunications operations were not a part of the Company's core businesses and would not align with the Company's commitment to serve retail customers on a long-term basis. The non-GAAP measures also provide a consistent basis upon which to measure performance by excluding the effects on per share earnings of abnormal weather in the electric business.

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Dividends Declared

SCANA’s Board of Directors has declared the following dividends on common stock during 2016:

Declaration Date	Dividend Per Share	Record Date	Payment Date
February 18, 2016	$0.575	March 10, 2016	April 1, 2016
April 28, 2016	$0.575	June 10, 2016	July 1, 2016

When a dividend payment date falls on a weekend or holiday, the payment is made the following business day.

Electric Operations

Electric Operations is comprised of the electric operations of SCE&G, GENCO and Fuel Company.  Electric operations operating income (including transactions with affiliates) was as follows:

Millions of dollars	2016		Change		2015
Operating revenues	$	592.7	(6.0	)%	$	630.3
Less:  Fuel used in electric generation	136.2		(21.9	)%	174.5
Purchased power	11.2		(12.5	)%	12.8
Margin	445.3		0.5	%	443.0
Other operation and maintenance expenses	125.0		4.8	%	119.3
Depreciation and amortization	70.5		(7.1	)%	75.9
Other taxes	52.1		6.3	%	49.0
Operating Income	$	197.7	(0.6	)%	$	198.8

• Margin increased due to base rate increases under the BLRA of $16.1 million and residential and commercial customer growth of $5.4 million. Margin also increased due to downward adjustments of $4.4 million in 2015, pursuant to orders of the SCPSC, related to SCE&G’s DSM Programs. These adjustments had no effect on net income as they were fully offset by the recognition, within other income, of gains realized upon the settlement of certain interest rate contracts. These increases were partially offset by $19.6 million due to the effects of abnormally cold weather in 2015 and abnormally mild weather in 2016 and lower industrial margins of $1.5 million.

• Operations and maintenance expenses increased due to higher labor costs of $6.0 million, primarily due to higher incentive compensation costs, and the amortization of $1.0 million of DSM Programs cost.

• Depreciation and amortization decreased by $7.3 million due to the implementation of SCPSC-approved revised (lower) depreciation rates in the third quarter of 2015. This decrease in depreciation expense was partially offset by increases associated with net plant additions.

• Other taxes increased due primarily to higher property taxes associated with net plant additions.

Sales volumes (in GWh) related to the electric operations margin above, by class, were as follows:

Classification	2016	Change		2015
Residential	1,926	(7.9	)%	2,092
Commercial	1,724	0.5	%	1,715
Industrial	1,503	2.4	%	1,468
Other	140	—	%	140
Total Retail Sales	5,293	(2.3	)%	5,415
Wholesale	223	(9.3	)%	246
Total Sales	5,516	(2.6	)%	5,661

Retail and wholesale sales volume decreased primarily due to the effects of weather.

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Gas Distribution

Gas Distribution is comprised of the local distribution operations of SCE&G and PSNC Energy.  Gas distribution operating income (including transactions with affiliates) was as follows:

Millions of dollars	2016		Change		2015
Operating revenues	$	299.9	(18.5	)%	$	368.1
Less:  Gas purchased for resale	132.7		(35.2	)%	204.7
Margin	167.2		2.3	%	163.4
Other operation and maintenance expenses	43.1		12.2	%	38.4
Depreciation and amortization	19.8		3.7	%	19.1
Other taxes	10.5		11.7	%	9.4
Operating Income	$	93.8	(2.8	)%	$	96.5

• Margin increased primarily due to customer growth.

• Operation and maintenance expenses increased due to higher labor costs of $2.8 million, primarily due to higher incentive compensation costs.

• Depreciation and amortization increased due to net plant additions, partially offset by reductions due to the implementation of SCPSC-approved revised (lower) depreciation rates.

• Other taxes increased due to net plant additions.

The effect of abnormal weather conditions on gas distribution margin is mitigated by the WNA (at SCE&G) and the CUT (at PSNC Energy), as further described in Note 1 of the consolidated financial statements in SCANA's Form 10-K for December 31, 2015. The WNA and the CUT affect margins but not sales volumes.

Sales volumes (in MMBTU) related to gas distribution margin by class, including transportation, were as follows:

Classification (in thousands)	2016	Change		2015
Residential	21,095	(13.8	)%	24,480
Commercial	11,090	(7.5	)%	11,992
Industrial	5,058	(1.4	)%	5,130
Transportation	10,818	6.4	%	10,169
Total	48,061	(7.2	)%	51,771

Residential and commercial firm sales volumes decreased primarily due to the effects of weather, partially offset by customer growth. Industrial firm sales volumes decreased due to the effects of weather, partially offset by customers shifting from interruptible to firm service due to favorable gas prices. Transportation volumes increased due to customers shifting to transportation only service and lower curtailments.

Retail Gas Marketing

Retail Gas Marketing is comprised of SCANA Energy, which operates in Georgia’s natural gas market.  Retail Gas Marketing operating revenues and net income were as follows:

Millions of dollars	2016		Change		2015
Operating revenues	$	171.0	(16.5	)%	$	204.7
Net income	21.8		(19.0	)%	26.9

Operating revenues and net income decreased due to lower demand and throughput.

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Energy Marketing

Energy Marketing is comprised of the Company’s non-regulated marketing operations, excluding SCANA Energy.  Energy Marketing operating revenues and net income were as follows:

Millions of dollars	2016		Change		2015
Operating revenues	$	132.4	(40.2	)%	$	221.4
Net income	2.5		(55.4	)%	5.6

Operating revenues decreased primarily due to lower market prices and lower demand. Net income decreased primarily due to higher transportation costs and lower demand. 

Other Operating Expenses

Other operating expenses were as follows:

Millions of dollars	2016		Change		2015
Other operation and maintenance	$	180.5	0.8	%	$	172.5
Depreciation and amortization	90.9		(6.6	)%	96.1
Other taxes	63.1		1.4	%	59.4

In addition to factors discussed in the electric operations and gas distribution segments, other operation and maintenance expenses decreased $2.2 million, depreciation and amortization decreased $0.7 million and other taxes decreased $0.5 million, all due to the sale of CGT in early 2015.

Other Income (Expense)

Other income (expense) includes the results of certain incidental non-utility activities of regulated subsidiaries, the activities of certain non-regulated subsidiaries and AFC. AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. The Company includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income. Components of other income and expense and AFC were as follows:

Millions of dollars	2016			Change		2015
Other income	$	15.8		(15.5	)%	$	18.7
Other expense	(13.8		)	12.2	%	(12.3		)
Gain on sale of SCI, net of transaction costs	—			(100.0	)%	107.4
AFC - equity funds	5.7			11.8	%	5.1

Other income decreased due primarily to the recognition in 2015 of $4.4 million of gains realized upon the settlement of certain interest rate contracts previously recorded as regulatory liabilities pursuant to SCPSC orders previously discussed. Such gain recognition was fully offset by downward adjustments to revenues reflected within electric margin and had no effect on net income (see electric margin discussion). Other income and other expense increased by $1.9 million for billings to DCGT for transition services provided at cost pursuant to the terms of the sale of CGT. Other income decreased by $3.9 million and other expense decreased by $2.3 million due to the sale of SCI. In 2015 other income also included the gain on the sale of SCI. AFC increased due to pipeline construction primarily at PSNC Energy.

Interest Expense

     Interest charges increased primarily due to increased borrowings.

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Income Taxes

Income taxes for the three months ended March 31, 2016 were lower than for the same period in 2015 primarily due to lower income before taxes. Income before taxes was higher in 2015 primarily due to the sales of CGT and SCI. The effective tax rate for 2015 was higher than the rate for 2016 due to discrete items related to the sales of CGT and SCI. 

LIQUIDITY AND CAPITAL RESOURCES

The Company anticipates that its cash obligations will be met through internally generated funds and additional short- and long-term borrowings. The Company expects that, barring a future impairment of the capital markets, it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future, including the cash requirements for nuclear construction and refinancing maturing long-term debt. The Company’s ratio of earnings to fixed charges for the three and 12 months ended March 31, 2016 was 3.92 and 3.25, respectively.

The Company is obligated with respect to an aggregate of $67.8 million of industrial revenue bonds which are secured by letters of credit issued by TD Bank N.A. The letters of credit expire, subject to renewal, in the fourth quarter of 2019.

At March 31, 2016, the Company had net available liquidity of approximately $1.2 billion, comprised of cash on hand and available amounts under lines of credit. The credit agreements total an aggregate of $2.0 billion, of which $200 million is scheduled to expire in December 2018 and the remainder is scheduled to expire in December 2020. The Company regularly monitors the commercial paper and short-term credit markets to optimize the timing of repayment of outstanding balances on its draws, if any, from the credit facilities. The Company’s long term debt portfolio has a weighted average maturity of approximately 20 years at a weighted average effective interest rate of 5.8%.  All of the long-term debt bears fixed interest rates or is swapped to fixed. To further preserve liquidity, the Company rigorously reviews its projected capital expenditures and operating costs and adjusts them where possible without impacting safety, reliability, and core customer service.

SCE&G has obtained FERC authority to issue short-term indebtedness and to assume liabilities as a guarantor(pursuant to Section 204 of the Federal Power Act). SCE&G may issue, with maturity dates of one year or less, unsecured promissory notes, commercial paper and direct loans in amounts not to exceed $1.6 billion outstanding and may enter into guaranty agreements in favor of lenders, banks, and dealers in commercial paper in amounts not to exceed $600 million. GENCO has obtained FERC authority to issue indebtedness with maturity dates of one year or less not to exceed $200 million outstanding. The authority described herein will expire in October 2016 and is expected to be renewed.

Cash provided from operating activities decreased primarily due to payments of income taxes in the first quarter of 2016, including certain amounts related to the gains on sales of CGT and SCI in 2015. Tax payments in the first quarter of 2015 were impacted by Congress' extension of bonus depreciation provisions late in 2014.

Cash flows from investing activities in 2016 related to capital expenditures and funding of collateral deposit requirements with respect to interest rate swaps as interest rates declined during the quarter. In 2015, similar investing cash outflows were more than offset by the receipt of proceeds from the sales of CGT and SCI.

Cash flows from financing activities in 2016 included normal dividend payments which were more than offset by increases in commercial paper balances. Similar financing activities in 2015 were offset by the use of the proceeds from the sales of CGT and SCI to reduce SCANA's long term debt and reduce Consolidated SCE&G's short term debt levels.

For additional information, see Note 4 to the combined notes to the condensed consolidated financial statements.

OTHER MATTERS

For information related to environmental matters, nuclear generation, and claims and litigation, see Note 9 of the combined notes to condensed consolidated financial statements.

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

The following discussion should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations appearing in SCE&G’s Annual Report on Form 10-K for the year ended December 31, 2015. 

RESULTS OF OPERATIONS

FOR THE THREE MONTHS ENDED MARCH 31, 2016

AS COMPARED TO THE CORRESPONDING PERIOD IN 2015

Net Income

Net income for Consolidated SCE&G was as follows:

Millions of dollars	2016		Change		2015
Net income	$	116.2	(8.0	)%	$	126.3

Net income decreased primarily due to higher operation and maintenance expense, higher property taxes, higher interest cost, and lower other income, partially offset by higher electric operations margin, higher gas distribution margin and lower depreciation expense, as further described below.

Dividends Declared

Consolidated SCE&G’s Boards of Directors declared the following dividends on common stock (all of which was held by SCANA) during 2016:

Declaration Date	Amount	Quarter Ended	Payment Date
February 18, 2016	$74.2 million	March 31, 2016	April 1, 2016
April 28, 2016	$75.2 million	June 30, 2016	July 1, 2016

Electric Operations

Electric Operations is comprised of the electric operations of SCE&G, GENCO and Fuel Company.  Electric operations operating income (including transactions with affiliates) was as follows:

Millions of dollars	2016		Change		2015
Operating revenues	$	592.7	(6.0	)%	$	630.3
Less: Fuel used in electric generation	136.2		(21.9	)%	174.5
Purchased power	11.2		(12.5	)%	12.8
Margin	445.3		0.5	%	443.0
Other operation and maintenance expenses	128.4		4.9	%	122.4
Depreciation and amortization	67.7		(7.6	)%	73.3
Other taxes	51.5		6.2	%	48.5
Operating Income	$	197.7	(0.6	)%	$	198.8

• Margin increased due to base rate increases under the BLRA of $16.1 million and residential and commercial customer growth of $5.4 million. Margin also increased due to downward adjustments of $4.4 million in 2015, pursuant to orders of the SCPSC, related to SCE&G’s DSM Programs. These adjustments had no effect on net income as they were fully offset by the recognition, within other income, of gains realized upon the settlement of certain interest rate contracts. These increases were partially offset by $19.6 million due to the effects of abnormally cold weather in 2015 and abnormally mild weather in 2016 and lower industrial margins of $1.5 million.

• Operations and maintenance expenses increased due to higher labor costs of $6.0 million, primarily due to higher incentive compensation costs, and the amortization of $1.0 million of DSM Programs cost.

• Depreciation and amortization decreased by $7.3 million due to the implementation of SCPSC-approved revised (lower) depreciation rates in the third quarter of 2015. This decrease in depreciation expense was partially offset by increases associated with net plant additions.

• Other taxes increased due primarily to higher property taxes associated with net plant additions.

43

Sales volumes (in GWh) related to the electric operations margin above, by class, were as follows:

Classification	2016	Change		2015
Residential	1,926	(7.9	)%	2,092
Commercial	1,724	0.5	%	1,715
Industrial	1,503	2.4	%	1,468
Other	140	—	%	140
Total Retail Sales	5,293	(2.3	)%	5,415
Wholesale	223	(9.3	)%	246
Total Sales	5,516	(2.6	)%	5,661

Retail and wholesale sales volumes decreased primarily due to the effects of weather.

Gas Distribution

Gas Distribution is comprised of the local distribution operations of SCE&G.  Gas distribution operating income (including transactions with affiliates) was as follows:

Millions of dollars	2016		Change		2015
Operating revenues	$	124.6	(12.4	)%	$	142.3
Less: Gas purchased for resale	55.6		(25.4	)%	74.5
Margin	69.0		1.8	%	67.8
Other operation and maintenance expenses	17.8		9.2	%	16.3
Depreciation and amortization	6.6		—	%	6.6
Other taxes	6.7		8.1	%	6.2
Operating Income	$	37.9	(2.1	)%	$	38.7

• Margin increased primarily due to customer growth.

• Operation and maintenance expenses increased due to higher labor costs of $0.8 million, primarily due to higher incentive compensation costs.

• Depreciation and amortization decreased $0.3 million due to the implementation of SCPSC-approved revised (lower) depreciation rates. This decrease in depreciation expense was offset by increases associated with net plant additions.

• Other taxes increased due to net plant additions.

The effect of abnormal weather conditions on gas distribution margin is mitigated by the WNA, as further described in Note 1 of the consolidated financial statements in SCE&G's Form 10-K for December 31, 2015. The WNA affects margins but not sales volumes.

Sales volumes (in MMBTU) related to gas distribution margin by class, including transportation, were as follows: 

Classification (in thousands)	2016	Change		2015
Residential	6,664	(13.4	)%	7,692
Commercial	4,391	(5.4	)%	4,643
Industrial	4,216	1.0	%	4,174
Transportation	1,170	9.6	%	1,068
Total	16,441	(6.5	)%	17,577

Residential and commercial firm sales volumes decreased primarily due to the effects of weather, partially offset by customer growth.  Industrial firm sales volumes increased due to customers shifting from interruptible to firm service due to favorable gas prices. Transportation volumes increased due to customers shifting to transportation only service.

44

Other Operating Expenses

Other operating expenses were as follows:

Millions of dollars	2016		Change		2015
Other operation and maintenance	$	146.2	5.4	%	$	138.7
Depreciation and amortization	74.3		(7.0	)%	79.9
Other taxes	58.2		6.4	%	54.7

Changes in other operating expenses are addressed in the electric operations and gas distribution segments.

Other Income (Expense)

Other income (expense) includes the results of certain incidental non-utility activities and AFC. AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. Consolidated SCE&G includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income. Components of other income and expense and AFC were as follows:

Millions of dollars	2016			Change		2015
Other income	$	5.6		(37.8	)%	$	9.0
Other expense	(7.7		)	1.3	%	(7.6		)
AFC - equity funds	4.7			(4.1	)%	4.9

Other income decreased due primarily to the recognition in 2015 of $4.4 million of gains realized upon the settlement of certain interest rate contracts previously recorded as regulatory liabilities pursuant to SCPSC orders previously discussed. Such gain recognition was fully offset by downward adjustments to revenues reflected within electric margin and had no effect on net income (see electric margin discussion).

Interest Expense

Interest charges increased primarily due to increased borrowings.

Income Taxes

Income taxes for the three months ended March 31, 2016 were lower than the same period in 2015 primarily due to lower income before taxes.

LIQUIDITY AND CAPITAL RESOURCES

Consolidated SCE&G anticipates that its cash obligations will be met through internally generated funds, additional short- and long-term borrowings, and equity contributions from its parent company.  Consolidated SCE&G expects that, barring a future impairment of the capital markets, it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future, including the cash requirements for nuclear construction and refinancing maturing long-term debt.  Consolidated SCE&G’s ratio of earnings to fixed charges for the three and 12 months ended March 31, 2016 was 3.47 and 3.58, respectively.

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.

At March 31, 2016, Consolidated SCE&G had net available liquidity of approximately $560.0 million, comprised of cash on hand and available amounts under lines of credit. The credit agreements total an aggregate of $1.4 billion, of which $200 million is scheduled to expire in December 2018 and the remainder is scheduled to expire in December 2020. Consolidated SCE&G regularly monitors the commercial paper and short-term credit markets to optimize the timing of repayment of outstanding balances on its draws, if any, from the credit facilities. Consolidated SCE&G’s long term debt portfolio has a weighted average maturity of approximately 23 years at a weighted average effective interest rate of 5.8%. All of the long-term debt bears fixed interest rates or is swapped to fixed. To further preserve liquidity, Consolidated SCE&G rigorously reviews its projected capital expenditures and operating costs and adjusts them where possible without impacting safety, reliability, and core customer service.

SCE&G has obtained FERC authority to issue short-term indebtedness and to assume liabilities as a guarantor(pursuant to Section 204 of the Federal Power Act). SCE&G may issue, with maturity dates of one year or less, unsecured promissory notes, commercial paper and direct loans in amounts not to exceed $1.6 billion outstanding and may enter into guaranty agreements in favor of lenders, banks, and dealers in commercial paper in amounts not to exceed $600 million. GENCO has obtained FERC authority to issue indebtedness with maturity dates of one year or less not to exceed $200 million outstanding. The authority described herein will expire in October 2016 and is expected to be renewed.

Cash used for operating activities increased primarily due to tax payments in the first quarter of 2016. Tax payments in the first quarter of 2015 were impacted by Congress' extension of bonus depreciation provisions late in 2014.

Cash flows from investing activities in 2016 and 2015 related to capital expenditures and funding of collateral deposit requirements with respect to interest rate swaps.

Cash flows from financing activities in 2016 and 2015 included normal dividend payments which were more than offset by increases in commercial paper and money pool borrowings.

For additional information, see Note 4 to the combined notes to condensed consolidated financial statements.

OTHER MATTERS

For information related to environmental matters, nuclear generation, and claims and litigation, see Note 9 of the combined notes to condensed consolidated financial statements.

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

SCANA:

Interest Rate Risk - Interest rates on all outstanding long-term debt are fixed either through the issuance of fixed rate debt or through the use of interest rate derivatives. The Company is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near future.

For further discussion of changes in long-term debt and interest rate derivatives, including changes in the Company's market risk exposures relative to interest rate risk, see ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – LIQUIDITY AND CAPITAL RESOURCES and also Notes 2, 4, 6 and 7 of the combined notes to condensed consolidated financial statements.

Commodity price risk - The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. See Note 6 and 7 of the combined notes to condensed consolidated financial statements. The following tables provide information about the Company’s financial instruments that are sensitive to changes in natural gas prices.  Weighted average settlement prices are per 10,000 MMBTU. Fair value represents quoted market prices for these or similar instruments.

45

Expected Maturity	2016	2017	2018
Futures - Long
Settlement Price (a)	2.34	2.83	3.05
Contract Amount (b)	18.4	10.5	1.3
Fair Value (b)	16.6	10.7	1.3
Futures - Short
Settlement Price (a)	2.32	2.82
Contract Amount (b)	1.3	0.6
Fair Value (b)	1.1	0.7
Options - Purchased Call (Long)
Strike Price (a)	2.95	3.09
Contract Amount (b)	15.6	12.2
Fair Value (b)	0.7	1.1
Swaps - Commodity
Pay fixed/receive variable (b)	28.5	10.6	5.8
Average pay rate (a)	3.2155	3.5291	3.5625
Average received rate (a)	2.2455	2.7896	2.8803
Fair value (b)	19.9	8.4	4.7
Pay variable/receive fixed (b)	20.4	10.4	5.4
Average pay rate (a)	2.2655	2.7909	2.9144
Average received rate (a)	3.1783	3.3732	3.4919
Fair value (b)	28.6	12.6	6.5
Swaps - Basis
Pay variable/receive variable (b)	2.2	1.1	1.0
Average pay rate (a)	2.2952	2.8441	3.0061
Average received rate (a)	2.2671	2.8411	2.9906
Fair value (b)	2.2	1.1	1.0
(a) Weighted average, in dollars
(b) Millions of dollars

ITEM 4. CONTROLS AND PROCEDURES

SCANA:

As of March 31, 2016, SCANA conducted an evaluation under the supervision and with the participation of its management, including its CEO and CFO, of (a) the effectiveness of the design and operation of its disclosure controls and procedures and (b) any change in its internal control over financial reporting.  Based on this evaluation, the CEO and CFO concluded that, as of March 31, 2016, SCANA’s disclosure controls and procedures were effective. There has been no change in SCANA’s internal control over financial reporting during the quarter ended March 31, 2016 that has materially affected or is reasonably likely to materially affect SCANA’s internal control over financial reporting.

SCE&G:

As of March 31, 2016, SCE&G conducted an evaluation under the supervision and with the participation of its management, including its CEO and CFO, of (a) the effectiveness of the design and operation of its disclosure controls and procedures and (b) any change in its internal control over financial reporting.  Based on this evaluation, the CEO and CFO concluded that, as of March 31, 2016, SCE&G’s disclosure controls and procedures were effective.  There has been no change in SCE&G’s internal control over financial reporting during the quarter ended March 31, 2016, that has materially affected or is reasonably likely to materially affect SCE&G’s internal control over financial reporting.

46

PART II.  OTHER INFORMATION

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

SCANA:

The following table provides information about purchases by or on behalf of SCANA or any affiliated purchaser (as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934, as amended (Exchange Act)) of shares or other units of any class of SCANA's equity securities that are registered pursuant to Section 12 of the Exchange Act:

Issuer Purchases of Equity Securities
	(a)	(b)		(c)	(d)
Period	Total number of shares (or units) purchased	Average price paid per share (or unit)		Total number of shares (or units) purchased as part of publicly announced plans or programs	Maximum number (or approximate dollar value) of shares (or units) that may yet be purchased under the plans or programs
January 1-31	8,353	$	60.53	8,353
February 1 - 29	—	—		—
March 1 - 31	—	—		—
Total	8,353			8,353	*

*The above table represents shares acquired for non-employee directors under the Director Compensation and Deferral Plan. On December 16, 2014 SCANA announced a program to convert from original issue to open market purchase of SCANA common stock for all applicable compensation and dividend reinvestment plans. This program took effect in the first quarter of 2015 and has no stated maximum number of shares that may be purchased and no stated expiration date.

ITEM 5.    OTHER INFORMATION

SCANA and SCE&G:

SCANA and SCE&G post information from time to time regarding developments relating to SCE&G’s new nuclear project and other matters of interest to investors on SCANA’s website at www.scana.com (which is not intended to be an active hyperlink; the information on SCANA’s website is not a part of this report or any other report or document that SCANA or SCE&G files with or furnishes to the SEC).  On SCANA’s homepage, there is a yellow box containing links to the Nuclear Development and Other Investor Information sections of the website.  The Nuclear Development section contains a yellow box with a link to project news and updates. The Other Investor Information section of the website contains a link to recent investor related information that cannot be found at other areas of the website.  Some of the information that will be posted from time to time, including the quarterly reports that SCE&G submits to the SCPSC and the ORS in connection with the new nuclear project, may be deemed to be material information that has not otherwise become public. Investors, media and other interested persons are encouraged to review this information and can sign up, under the Investor Relations Section of the website, for an email alert when there is a new posting in the Nuclear Development and Other Investor Information yellow box.

ITEM 6. EXHIBITS

SCANA and SCE&G:

Exhibits filed or furnished with this Quarterly Report on Form 10-Q are listed in the following Exhibit Index.

As permitted under Item 601(b) (4) (iii) of Regulation S-K, instruments defining the rights of holders of long-term debt of less than 10 percent of the total consolidated assets of SCANA, for itself and its subsidiaries, and of SCE&G, for itself and its consolidated affiliates, have been omitted and SCANA and SCE&G agree to furnish a copy of such instruments to the SEC upon request.

47

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each of the registrants has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.  The signature of each registrant shall be deemed to relate only to matters having reference to such registrant and any subsidiaries thereof.

SCANA CORPORATION

SOUTH CAROLINA ELECTRIC & GAS COMPANY

(Registrants)

	By:	/s/James E. Swan, IV
Date: May 6, 2016		James E. Swan, IV
		Vice President and Controller
		(Principal accounting officer)

48

EXHIBIT INDEX

	Applicable to Form 10-Q of
Exhibit No.	SCANA	SCE&G	Description
3.01	X		Restated Articles of Incorporation of SCANA, as adopted on April 26, 1989 (Filed as Exhibit 3-A to Registration Statement No. 33-49145 and incorporated by reference herein)
3.02	X		Articles of Amendment dated April 27, 1995 (Filed as Exhibit 4-B to Registration Statement No. 33-62421 and incorporated by reference herein)
3.03	X		Articles of Amendment effective April 25, 2011 (Filed as Exhibit 4.03 to Registration Statement No. 333-174796 and incorporated by reference herein)
3.04		X	Restated Articles of Incorporation of SCE&G, as adopted on December 30, 2009 (Filed as Exhibit 1 to Form 8-A (File Number 000-53860) and incorporated by reference herein)
3.05	X		By-Laws of SCANA as amended and restated as of February 19, 2009 (Filed as Exhibit 4.04 to Registration Statement No. 333-174796 and incorporated by reference herein)
3.06		X	By-Laws of SCE&G as revised and amended on February 22, 2001 (Filed as Exhibit 3.05 to Registration Statement No. 333-65460 and incorporated by reference herein)
12.01	X	X	Statement Re Computation of Ratios (Filed herewith)
31.01	X		Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)
31.02	X		Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)
31.03		X	Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)
31.04		X	Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)
32.01	X		Certification of Principal Executive Officer and Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
32.02		X	Certification of Principal Executive Officer and Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
101. INS*	X	X	XBRL Instance Document
101. SCH*	X	X	XBRL Taxonomy Extension Schema
101. CAL*	X	X	XBRL Taxonomy Extension Calculation Linkbase
101. DEF*	X	X	XBRL Taxonomy Extension Definition Linkbase
101. LAB*	X	X	XBRL Taxonomy Extension Label Linkbase
101. PRE*	X	X	XBRL Taxonomy Extension Presentation Linkbase

*   Pursuant to Rule 406T of Regulation S-T, this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.

49

EX-12.01

Exhibit 12.01

COMPUTATION OF RATIOS

March 31, 2016

RATIO OF EARNINGS TO FIXED CHARGES

SCANA:	Three Months Ended March 31, 2016		Twelve Months Ended March 31, 2016		Years ended December 31,
Dollars in Millions					2015		2014			2013			2012			2011
Fixed Charges as defined:
Interest on debt		$85.7		$334.0		$327.8		$318.2			$305.9			$301.3			$287.0
Amortization of debt premium, discount and expense (net)	1.1		4.5		4.7		9.7			5.3			4.9			4.8
Interest component on rentals	0.9		3.7		3.7		4.1			4.9			4.9			5.2
Total Fixed Charges (A)		$87.7		$342.2		$336.2		$332.0			$316.1			$311.1			$297.0
Earnings as defined:
Pretax income from continuing operations		$255.5	$766.5			$1138.4		$786.0			$693.8			$601.6			$555.6
Total fixed charges above	87.7		342.2		336.2		332.0			316.1			311.1			297.0
Pretax equity in (earnings) losses of investees	0.1		0.8		0.8		(1.4		)	(3.2		)	(3.3		)	(2.9		)
Cash distributions from equity investees	0.9		3.5		4.0		7.4			9.6			3.3			3.6
Total Earnings (B)	$344.2		$1,113.0		$1,479.4		$1,124.0			$1,016.3				$912.7			$853.3
Ratio of Earnings to Fixed Charges (B/A)	3.92		3.25		4.40		3.39			3.22			2.93			2.87

SCE&G:	Three Months Ended March 31, 2016		Twelve Months Ended March 31, 2016		Years ended December 31,
Dollars in Millions					2015		2014		2013		2012		2011
Fixed Charges as defined:
Interest on debt		$68.2		$265.3		$258.4		$237.6		$226.4		$217.4		$207.8
Amortization of debt premium, discount and expense (net)	0.9		3.5		3.7		4.4		4.2		3.9		3.9
Interest component on rentals	1.0		4.1		4.1		4.0		4.5		3.2		3.6
Total Fixed Charges (A)		$70.1		$272.9		$266.2		$246.0		$235.1		$224.5		$215.3
Earnings as defined:
Pretax income from continuing operations		$172.4		$699.1		$711.0		$676.0		$579.7		$509.5		$456.5
Total fixed charges above	70.1		272.9		266.2		246.0		235.1		224.5		215.3
Pretax equity in losses of investees	1.0		4.4		5.0		5.3		3.5		3.8		2.3
Total Earnings (B)		$243.5		$976.4		$982.2		$927.3		$818.3		$737.8		$674.1
Ratio of Earnings to Fixed Charges (B/A)	3.47		3.58		3.69		3.77		3.48		3.29		3.13

EX-31.01

Exhibit 31.01

CERTIFICATION

I, Kevin B. Marsh, certify that:

1. I have reviewed this quarterly report on Form 10-Q of SCANA Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 6, 2016
	/s/Kevin B. Marsh
	Kevin B. Marsh
	Chairman of the Board, President, Chief Executive Officer and
	Chief Operating Officer

EX-31.02

Exhibit 31.02

CERTIFICATION

I, Jimmy E. Addison, certify that:

1. I have reviewed this quarterly report on Form 10-Q of SCANA Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 6, 2016
	/s/Jimmy E. Addison
	Jimmy E. Addison
	Executive Vice President and Chief Financial Officer

EX-31.03

Exhibit 31.03

CERTIFICATION

I, Kevin B. Marsh, certify that:

1. I have reviewed this quarterly report on Form 10-Q of South Carolina Electric & Gas Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 6, 2016
	/s/Kevin B. Marsh
	Kevin B. Marsh
	Chairman of the Board and Chief Executive Officer

EX-31.04

Exhibit 31.04

CERTIFICATION

I, Jimmy E. Addison, certify that:

1. I have reviewed this quarterly report on Form 10-Q of South Carolina Electric & Gas Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 6, 2016
	/s/Jimmy E. Addison
	Jimmy E. Addison
	Executive Vice President and Chief Financial Officer

EX-32.01

Exhibit 32.01 

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of SCANA Corporation (the “Company”) on Form 10-Q for the quarter ended March 31, 2016 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), we certify pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: May 6, 2016
/s/Kevin B. Marsh	/s/Jimmy E. Addison
Kevin B. Marsh	Jimmy E. Addison
Chairman of the Board, President, Chief Executive Officer	Executive Vice President and Chief Financial Officer
and Chief Operating Officer

EX-32.02

Exhibit 32.02

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of South Carolina Electric & Gas Company (the “Company”) on Form 10-Q for the quarter ended March 31, 2016 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), we certify pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: May 6, 2016
/s/Kevin B. Marsh	/s/Jimmy E. Addison
Kevin B. Marsh	Jimmy E. Addison
Chairman of the Board and Chief Executive Officer	Executive Vice President and Chief Financial Officer

XML

Document and Entity Information Document	3 Months Ended
	Mar. 31, 2016 shares
Entity Information [Line Items]
Entity Registrant Name	SCANA Corporation
Entity Central Index Key	0000754737
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Mar. 31, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q1
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	0000091882
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-Q
Document Period End Date	Mar. 31, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding	40,296,147

XML

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Assets
Utility Plant In Service	$ 12,942	$ 12,883
Accumulated Depreciation and Amortization	(4,327)	(4,307)
Construction Work in Progress	4,245	4,051
Nuclear Fuel, Net of Accumulated Amortization	295	308
Goodwill, Net of Writedown of $230	210	210
Utility Plant, Net	13,365	13,145
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	280	280
Assets held in trust, net-nuclear decommissioning	119	115
Other investments	73	71
Nonutility Property and Investments, Net	472	466
Current Assets:
Cash and cash equivalents	86	176
Receivables, net of allowance for uncollectible accounts	505	505
Other	142	227
Inventories (at average cost):
Fuel	134	164
Materials and supplies	148	148
Prepaid Expense	119	115
Other current assets	83	43
Total Current Assets	1,217	1,378
Deferred Debits and Other Assets:
Regulatory Assets, Noncurrent	2,068	1,937
Other	246	220
Total Deferred Debits and Other Assets	2,314	2,157
Total	17,368	17,146
Capitalization and Liabilities
Common Stock, Value, Outstanding	2,390	2,390
Retained Earnings, Unappropriated	3,212	3,118
Accumulated Other Comprehensive Income (Loss), Net of Tax	(63)	(65)
Stockholders' Equity Attributable to Parent	5,539	5,443
Long-term Debt, Excluding Current Maturities	5,879	5,882
Total Capitalization	11,418	11,325
Current Liabilities:
Short-term borrowings	917	531
Current portion of long-term debt	116	116
Accounts payable	369	590
Customer deposits and customer prepayments	176	137
Taxes accrued	83	242
Interest accrued	85	83
Dividends declared	80	76
Derivative financial instruments	113	50
Other	92	127
Total Current Liabilities	2,031	1,952
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,898	1,907
Asset retirement obligations	522	520
Pension and other postretirement benefits	318	315
Regulatory Liabilities	847	855
Other	334	272
Total Deferred Credits and Other Liabilities	$ 3,919	$ 3,869
Commitments and Contingencies
Total	$ 17,368	$ 17,146
SCEG
Assets
Utility Plant In Service	11,195	11,153
Accumulated Depreciation and Amortization	(3,883)	(3,869)
Construction Work in Progress	4,141	3,997
Nuclear Fuel, Net of Accumulated Amortization	295	308
Utility Plant, Net	11,748	11,589
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	68	68
Assets held in trust, net-nuclear decommissioning	119	115
Other investments	1	1
Nonutility Property and Investments, Net	188	184
Current Assets:
Cash and cash equivalents	57	130
Receivables, net of allowance for uncollectible accounts	320	324
Other	114	202
Due from Affiliate, Current	15	22
Inventories (at average cost):
Fuel	92	98
Materials and supplies	135	136
Prepaid Expense	87	92
Other current assets	52	15
Total Current Assets	872	1,019
Deferred Debits and Other Assets:
Regulatory Assets, Noncurrent	1,986	1,857
Other	138	116
Total Deferred Debits and Other Assets	2,124	1,973
Total	14,932	14,765
Capitalization and Liabilities
Common Stock, Value, Outstanding	2,760	2,760
Retained Earnings, Unappropriated	2,306	2,265
Accumulated Other Comprehensive Income (Loss), Net of Tax	(3)	(3)
Stockholders' Equity Attributable to Parent	5,063	5,022
Stockholders' Equity Attributable to Noncontrolling Interest	130	129
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	5,193	5,151
Long-term Debt, Excluding Current Maturities	4,656	4,659
Total Capitalization	9,849	9,810
Current Liabilities:
Short-term borrowings	870	420
Current portion of long-term debt	111	110
Accounts payable	245	469
Due to Affiliate, Current	116	113
Customer deposits and customer prepayments	129	93
Taxes accrued	76	299
Interest accrued	66	66
Dividends declared	74	75
Derivative financial instruments	101	34
Other	42	61
Total Current Liabilities	1,830	1,740
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,717	1,732
Asset retirement obligations	490	488
Pension and other postretirement benefits	188	186
Regulatory Liabilities	623	635
Other	218	157
Other -affiliate	17	17
Total Deferred Credits and Other Liabilities	3,253	3,215
Total	$ 14,932	$ 14,765

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) shares in Millions, $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Common Stock, Shares, Outstanding	142.9	142.9
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	$ 128	$ 124
Public Utilities, Property, Plant and Equipment, Net	13,365	13,145
Allowance for Doubtful Accounts Receivable, Current	5	5
Write-down, Goodwill	230	230
Assets, Current	1,217	1,378
Regulated Entity, Other Assets, Noncurrent	$ 2,314	$ 2,157
SCEG
Common Stock, Shares, Outstanding	40.3	40.3
Public Utilities, Property, Plant and Equipment, Net	$ 11,748	$ 11,589
Allowance for Doubtful Accounts Receivable, Current	3	3
Assets, Current	872	1,019
Regulated Entity, Other Assets, Noncurrent	2,124	1,973
SCEG | Variable Interest Entity, Primary Beneficiary [Member]
Public Utilities, Property, Plant and Equipment, Net	683	700
Assets, Current	90	88
Regulated Entity, Other Assets, Noncurrent	$ 58	$ 53

XML

CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Operating Revenues:
Electric Domestic Regulated Revenue	$ 592	$ 629
Regulated Operating Revenue, Gas	299	369
Gas-nonregulated	281	391
Regulated and Unregulated Operating Revenue	1,172	1,389
Operating Expenses [Abstract]
Fuel used in electric generation	136	174
Purchased power	11	13
Gas purchased for resale	359	523
Other operation and maintenance	181	173
Depreciation and amortization	91	96
Other taxes	63	59
Total Operating Expenses	841	1,038
Gain (Loss) on Disposition of Regulated Business Net of Transaction Costs	0	235
Operating Income	331	586
Other Income (Expense):
Other income	16	19
Other expense	(14)	(12)
Gain (Loss) On Disposition Of Unregulated Business Net Of Transaction Costs	0	107
Interest Expense	(83)	(77)
Allowance for equity funds used during construction	5	5
Total Other Expense	(76)	42
Income Before Income Tax Expense	255	628
Income Tax Expense	79	228
Net Income	$ 176	$ 400
Earnings Per Share, Basic and Diluted	$ 1.23	$ 2.80
Per Common Share Data
Weighted Average Number of Shares Outstanding, Basic and Diluted	142.9	142.9
Weighted Average Common Shares Outstanding (millions)
Dividends, Common Stock	$ 82
SCEG
Operating Revenues:
Electric Domestic Regulated Revenue	593	$ 630
Regulated Operating Revenue, Gas	124	142
Regulated Operating Revenue	717	772
Operating Expenses [Abstract]
Fuel used in electric generation	136	174
Purchased power	11	13
Gas purchased for resale	56	74
Other operation and maintenance	146	139
Depreciation and amortization	74	80
Other taxes	58	55
Total Operating Expenses	481	535
Operating Income	236	237
Other Income (Expense):
Other income	5	9
Other expense	(8)	(8)
Interest Expense	(66)	(59)
Allowance for equity funds used during construction	5	5
Total Other Expense	(64)	(53)
Income Before Income Tax Expense	172	184
Income Tax Expense	56	58
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	116	126
Net Income (Loss) Attributable to Noncontrolling Interest	(3)	(4)
Earnings Available to Common Shareholder	113	122
Weighted Average Common Shares Outstanding (millions)
Dividends, Common Stock	$ 74	$ 71

XML

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Allowance for Funds Used During Construction, Capitalized Interest	$ 4	$ 3
SCEG
Allowance for Funds Used During Construction, Capitalized Interest	$ 3	$ 3

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Net Income (Loss) Attributable to Parent [Abstract]
Net Income (Loss) Available to Common Stockholders, Basic	$ 176	$ 400
Other Comprehensive Income (Loss)
Unrealized gains (losses) on cash flow hedging activities arising during period	(5)	(3)
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	2	6
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, before Reclassification Adjustments, Net of Tax	0	4
Other Comprehensive Income (Loss)	2	2
Comprehensive income available to common shareholder	178	402
SCEG
Other Comprehensive Income (Loss)
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	116	126
Genco
Other Comprehensive Income (Loss)
Less comprehensive income attributable to noncontrolling interest	3	4
SCE&G (including Fuel Company)
Net Income (Loss) Attributable to Parent [Abstract]
Net Income (Loss) Available to Common Stockholders, Basic	113	122
Other Comprehensive Income (Loss)
Comprehensive income available to common shareholder	113	122
Commodity Contract
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	5	7
Interest Rate Contract
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	2	2
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)

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Tax	$ 0	$ (3)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	(3)	(2)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax	1	1
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income, Tax	3	5
Commodity Contract
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 5	$ 7

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Cash Flows From Operating Activities:
Net Income (Loss) Available to Common Stockholders, Basic	$ 176	$ 400
Adjustments to reconcile net income to net cash provided from operating activities:
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal		(353)
Loss from Equity Method Investments, Net of Dividends or Distributions		1
Deferred Income Tax Expense (Benefit)	(11)	(74)
Depreciation and amortization	94	100
Amortization of nuclear fuel	14	13
Allowance for equity funds used during construction	(5)	(5)
Carrying cost recovery	(4)	(3)
Cash provided (used) by changes in certain assets and liabilities:
Increase (Decrease) in Receivables	0	33
Increase (Decrease) in Inventories	11	31
increase (Decrease) in Prepaid Expense	(11)	218
Increase (Decrease) in Other Regulatory Assets	0	28
Increase (Decrease) in Regulatory liabilities	(1)	6
Increase (Decrease ) in Accounts payable	(39)	(67)
Increase (Decrease) in Taxes accrued	(159)	(71)
Increase (Decrease) in Derivative Assets and Liabilities	(3)	(22)
Changes in other assets	(20)	(6)
Changes in other liabilities	19	(34)
Net Cash Provided From Operating Activities	61	195
Cash Flows From Investing Activities:
Property additions and construction expenditures	(385)	(352)
Proceeds from Sale of Property, Plant, and Equipment	0	645
Proceeds from investments (including derivative collateral posted)	198	318
Purchase of investments (including derivative collateral posted)	(264)	(400)
Net Cash Used in Investing Activities	(451)	211
Cash Flows From Financing Activities:
Proceeds from Issuance of Common Stock	0	14
Repayments of Long-term Debt	(8)	(158)
Dividends	(78)	(75)
Short-term borrowings, net	386	(293)
Net Cash Provided From Financing Activities	300	(512)
Net (Decrease) Increase in Cash and Cash Equivalents	(90)	(106)
Cash and Cash Equivalents, January 1	176	137
Cash and Cash Equivalents, March 31	86	31
Supplemental Cash Flow Information:
Cash paid for-Interest (net of capitalized interest )	77	81
Cash paid for-Income taxes	141	8
Noncash Investing and Financing Activities:
Accrued construction expenditures	142	84
Capital Lease Obligations Incurred	5	2
SCEG
Cash Flows From Operating Activities:
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	116	126
Adjustments to reconcile net income to net cash provided from operating activities:
Loss from Equity Method Investments	1	1
Deferred Income Tax Expense (Benefit)	(15)	7
Depreciation and amortization	76	82
Amortization of nuclear fuel	14	13
Allowance for equity funds used during construction	(5)	(5)
Carrying cost recovery	(4)	(3)
Cash provided (used) by changes in certain assets and liabilities:
Increase (Decrease) in Receivables	7	(68)
Increase (Decrease) in Due from Affiliates, Current	(2)	90
Increase (Decrease) in Inventories	(3)	0
increase (Decrease) in Prepaid Expense	(3)	75
Increase (Decrease) in Other Regulatory Assets	2	22
Increase (Decrease) in Regulatory liabilities	(1)	6
Increase (Decrease ) in Accounts payable	(23)	(205)
Increase (Decrease) in Due to Affiliate, Current	(8)	185
Increase (Decrease) in Taxes accrued	(223)	(50)
Changes in other assets	(9)	(3)
Changes in other liabilities	25	(49)
Net Cash Provided From Operating Activities	(55)	224
Cash Flows From Investing Activities:
Property additions and construction expenditures	(337)	(319)
Proceeds from investments (including derivative collateral posted)	171	274
Purchase of investments (including derivative collateral posted)	(239)	(356)
Investment In Affiliate	9	80
Net Cash Used in Investing Activities	(396)	(321)
Cash Flows From Financing Activities:
Repayments of Long-term Debt	(8)	(8)
Dividends	(75)	(74)
Return of Capital to Parent		(4)
Short-term borrowings-affiliate,net	11	192
Short-term borrowings, net	450	(99)
Net Cash Provided From Financing Activities	378	7
Net (Decrease) Increase in Cash and Cash Equivalents	(73)	(90)
Cash and Cash Equivalents, January 1	130	100
Cash and Cash Equivalents, March 31	57	10
Supplemental Cash Flow Information:
Cash paid for-Interest (net of capitalized interest )	63	62
Income Taxes Paid	175
Proceeds from Income Tax Refunds	7	83
Noncash Investing and Financing Activities:
Accrued construction expenditures	109	76
Capital Lease Obligations Incurred	$ 5	$ 2

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Interest Paid, Capitalized	$ 4	$ 3
SCEG
Interest Paid, Capitalized	$ 3	$ 3

XML

CONSOLIDATED STATEMENTS OF COMMON EQUITY Statement - USD ($) shares in Millions, $ in Millions	Total	AOCI Attributable to Parent [Member]	Reclassification out of Accumulated Other Comprehensive Income [Member]	SCEG	SCEG excluding VIEs [Member]	Noncontrolling Interest [Member]
Stockholders' Equity before Treasury Stock	$ 2,388
Treasury Stock, Value	(10)
Retained Earnings, Appropriated	2,684				$ 2,077
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	(63)
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	(12)
Accumulated Other Comprehensive Income (Loss)	(75)				$ (3)
Stockholders' Equity Attributable to Noncontrolling Interest						$ 123
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest				$ 4,757
Stockholders' Equity Attributable to Parent	$ 4,987
Shares, Outstanding	143				40
Common Stock, Value, Outstanding					$ 2,560
Stock Issued During Period, Value, Other	$ 14
Common Stock, Dividends, Per Share, Declared	$ 0.545
Net Income (Loss) Available to Common Stockholders, Basic	$ 400				122
Net Income (Loss) Attributable to Noncontrolling Interest				4		4
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest				126
Proceeds from Contribution from Parent, net of return of Proceeds					(4)
Dividends				70	69
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders						(1)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	(3)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax	(4)
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	6
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	9
Other Comprehensive Income (Loss)	2
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	$ 402				122
Stock Issued During Period, Shares, New Issues	0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax	$ 0
Dividends, Common Stock				(71)
Stockholders' Equity before Treasury Stock	2,402
Treasury Stock, Value	(10)
Retained Earnings, Appropriated	3,006				2,130
AOCI before Tax, Attributable to Parent		$ (7)	$ (9)
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	(57)
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	(16)
Accumulated Other Comprehensive Income (Loss)	(73)				$ (3)
Stockholders' Equity Attributable to Noncontrolling Interest						126
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest				4,809
Stockholders' Equity Attributable to Parent	$ 5,325
Shares, Outstanding	143				40
Common Stock, Value, Outstanding					$ 2,556
Stockholders' Equity before Treasury Stock	$ 2,402
Treasury Stock, Value	(12)
Retained Earnings, Appropriated	3,118			2,265	2,265
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	(53)
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	(12)
Accumulated Other Comprehensive Income (Loss)	(65)				$ (3)
Stockholders' Equity Attributable to Noncontrolling Interest				129		129
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest				5,151
Stockholders' Equity Attributable to Parent	$ 5,443			5,022
Shares, Outstanding	143				40
Common Stock, Value, Outstanding	$ 2,390			2,760	$ 2,760
Common Stock, Dividends, Per Share, Declared	$ 0.575
Net Income (Loss) Available to Common Stockholders, Basic	$ 176				113
Net Income (Loss) Attributable to Noncontrolling Interest				3		3
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest				116
Dividends				74	72
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders						(2)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	(5)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax	0
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	2
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	7
Other Comprehensive Income (Loss)	2
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	178				113
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax	0
Dividends, Common Stock	(82)			(74)
Stockholders' Equity before Treasury Stock	2,402
Treasury Stock, Value	(12)
Retained Earnings, Appropriated	3,212			2,306	2,306
AOCI before Tax, Attributable to Parent		$ (5)	$ (7)
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	(51)
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	(12)
Accumulated Other Comprehensive Income (Loss)	(63)				$ (3)
Stockholders' Equity Attributable to Noncontrolling Interest				130		$ 130
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest				5,193
Stockholders' Equity Attributable to Parent	$ 5,539			5,063
Shares, Outstanding	143				40
Common Stock, Value, Outstanding	$ 2,390			$ 2,760	$ 2,760

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

3 Months Ended

Mar. 31, 2016

Significant Accounting Policies

Significant Accounting Policies [Text Block]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Consolidation and Variable Interest Entities

The condensed consolidated financial statements of the Company include, after eliminating intercompany balances and transactions, the accounts of the parent holding company and each of its subsidiaries, including Consolidated SCE&G. Accordingly, discussions regarding the Company's financial results necessarily include the results of Consolidated SCE&G.

SCE&G has determined that it has a controlling financial interest in GENCO and Fuel Company (which are considered to be VIEs) and, accordingly, Consolidated SCE&G's condensed consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. As a result, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s condensed consolidated financial statements.

GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $488 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.

Income Statement Presentation

Revenues and expenses arising from regulated businesses and, in the case of the Company, retail natural gas marketing businesses (including those activities of segments described in Note 10) are presented within operating income, and all other activities are presented within other income (expense). Consistent with this presentation, the Company presents the 2015 gain on the sale of CGT within operating income and the 2015 gain on the sale of SCI within other income (expense).

Asset Management and Supply Service Agreement

PSNC Energy, a subsidiary of SCANA, utilizes an asset management and supply service agreement with a counterparty for certain natural gas storage facilities.  Such counterparty held 29% and 46% of PSNC Energy’s natural gas inventory at March 31, 2016 and December 31, 2015, respectively, with a carrying value of $6.0 million and $17.7 million, respectively, through an agency relationship.  Under the terms of the asset management agreement, PSNC Energy receives storage asset management feesof which 75% are credited to rate payers. No fees are received under the supply service agreement. This agreement expires on March 31, 2017.

Earnings Per Share

The Company computes basic earnings per share by dividing net income by the weighted average number of common shares outstanding for the period. The Company computes diluted earnings per share using this same formula, after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method. The weighted average number of common shares for each period presented for basic and diluted earnings per share purposes were identical.

Dispositions

In the first quarter of 2015, SCANA sold CGT and SCI. CGT was an interstate natural gas pipeline regulated by FERC that transported natural gas in South Carolina and southeastern Georgia, and it was sold to Dominion Resources, Inc. SCI provided fiber optic communications and other services and built, managed and leased communications towers in several southeastern states, and it was sold to a subsidiary of Spirit Communications. These sales resulted in recognition of pre-tax gains totaling approximately $342 million. As previously noted, the pre-tax gain from the sale of CGT is included within Operating Income and the pre-tax gain from the sale of SCI is included within Other Income (Expense) on the Company's condensed consolidated statement of income.

CGT and SCI operated principally in wholesale markets, whereas the Company's primary focus is the delivery of energy-related products and services to retail markets. In addition, neither CGT nor SCI met accounting criteria for disclosure as a reportable segment and were included within the All Other caption in Note 10. The sales of CGT and SCI did not represent a strategic shift that had a major effect on the Company's operations; therefore, these sales did not meet the criteria for classification as discontinued operations.

Reclassifications

Certain prior period amounts within the reconciliations of Net income to Net Cash Provided From Operating Activities on the Condensed Consolidated Statements of Cash Flows of the Company and Consolidated SCE&G have been reclassified to conform to the current period presentation. Specifically, $81 million of non-cash changes in fair value of interest rate swaps has been reclassified from the Derivative financial instruments caption, with offsetting reclassifications of $96 million and $(15) million within changes in the Regulatory assets and changes in Other liabilities captions, respectively. Additionally, due to insignificance, the captions for changes in Interest accrued and changes in Pension and other postretirement benefits which were utilized in the reconciliation for the prior period have been eliminated and their amounts included within changes in Other liabilities. These reclassifications had no effect on Net Cash Provided From Operating Activities or on any other subtotal in the Condensed Consolidated Statements of Cash Flows.

New Accounting Matters

In May 2014, the FASB issued accounting guidance for revenue arising from contracts with customers that supersedes most current revenue recognition guidance, including industry-specific guidance. This revenue recognition model provides a

five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the

transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive

in exchange for those goods or services. This guidance must be adopted no later than the first quarter of 2018, and early

adoption is permitted in the first quarter of 2017. Adoption using a retrospective method is required, with options to elect

certain practical expedients or to recognize a cumulative effect in the year of initial adoption. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what practical expedients will be elected. The Company and Consolidated SCE&G have not determined the impact this guidance will have on their respective financial statements.

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. This guidance was adopted in the first quarter of 2016 and had no impact on the Company’s or Consolidated SCE&G's financial statements.

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 and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2017. The Company and Consolidated SCE&G are evaluating this guidance and have not determined what impact it will have on their respective financial statements.

In January 2016, the FASB issued accounting guidance intended to clarify the classification and measurement of financial instruments and financial liabilities, among other things. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018. The Company and Consolidated SCE&G are evaluating this guidance and have not determined what impact it will have on their respective financial statements.

In February 2016, the FASB issued accounting guidance related to the recognition, measurement and presentation of

leases. The guidance applies a right-of-use model and, for lessees, requires all leases with a duration over twelve months to be

recorded on the balance sheet, with the rights of use treated as assets and the payment obligations treated as liabilities. Further,

and without consideration of any regulatory accounting requirements which may apply, depending primarily of the nature of the

assets and the relative consumption of them, lease costs will be recognized either through the separate amortization of the right-of-use asset and the recognition of the interest cost related to the payment obligation, or through the recording of a combined

straight-line rental expense. For lessors, the guidance calls for the recognition of income either through the derecognition of

assets and subsequent recording of interest income on lease amounts receivable, or through the recognition of rental income on

a straight line basis, also depending on the nature of the assets and relative consumption. The guidance will be effective for

years beginning in 2019. The Company and Consolidated SCE&G have not determined what impact this guidance will have on their respective financial statements.

In March 2016, the FASB issued accounting guidance changing how companies account for certain aspects of share-based payments to employees. Entities will be required to recognize the income tax effects of awards in the income statement when the awards vest or are settled. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2017. The Company and Consolidated SCE&G are evaluating this guidance and have not determined what impact it will have on their respective financial statements.

SCEG

Significant Accounting Policies

Significant Accounting Policies [Text Block]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Consolidation and Variable Interest Entities

The condensed consolidated financial statements of the Company include, after eliminating intercompany balances and transactions, the accounts of the parent holding company and each of its subsidiaries, including Consolidated SCE&G. Accordingly, discussions regarding the Company's financial results necessarily include the results of Consolidated SCE&G.

SCE&G has determined that it has a controlling financial interest in GENCO and Fuel Company (which are considered to be VIEs) and, accordingly, Consolidated SCE&G's condensed consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. As a result, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s condensed consolidated financial statements.

GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $488 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.

Income Statement Presentation

Revenues and expenses arising from regulated businesses and, in the case of the Company, retail natural gas marketing businesses (including those activities of segments described in Note 10) are presented within operating income, and all other activities are presented within other income (expense). Consistent with this presentation, the Company presents the 2015 gain on the sale of CGT within operating income and the 2015 gain on the sale of SCI within other income (expense).

Asset Management and Supply Service Agreement

PSNC Energy, a subsidiary of SCANA, utilizes an asset management and supply service agreement with a counterparty for certain natural gas storage facilities.  Such counterparty held 29% and 46% of PSNC Energy’s natural gas inventory at March 31, 2016 and December 31, 2015, respectively, with a carrying value of $6.0 million and $17.7 million, respectively, through an agency relationship.  Under the terms of the asset management agreement, PSNC Energy receives storage asset management feesof which 75% are credited to rate payers. No fees are received under the supply service agreement. This agreement expires on March 31, 2017.

Earnings Per Share

The Company computes basic earnings per share by dividing net income by the weighted average number of common shares outstanding for the period. The Company computes diluted earnings per share using this same formula, after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method. The weighted average number of common shares for each period presented for basic and diluted earnings per share purposes were identical.

Dispositions

In the first quarter of 2015, SCANA sold CGT and SCI. CGT was an interstate natural gas pipeline regulated by FERC that transported natural gas in South Carolina and southeastern Georgia, and it was sold to Dominion Resources, Inc. SCI provided fiber optic communications and other services and built, managed and leased communications towers in several southeastern states, and it was sold to a subsidiary of Spirit Communications. These sales resulted in recognition of pre-tax gains totaling approximately $342 million. As previously noted, the pre-tax gain from the sale of CGT is included within Operating Income and the pre-tax gain from the sale of SCI is included within Other Income (Expense) on the Company's condensed consolidated statement of income.

CGT and SCI operated principally in wholesale markets, whereas the Company's primary focus is the delivery of energy-related products and services to retail markets. In addition, neither CGT nor SCI met accounting criteria for disclosure as a reportable segment and were included within the All Other caption in Note 10. The sales of CGT and SCI did not represent a strategic shift that had a major effect on the Company's operations; therefore, these sales did not meet the criteria for classification as discontinued operations.

Reclassifications

Certain prior period amounts within the reconciliations of Net income to Net Cash Provided From Operating Activities on the Condensed Consolidated Statements of Cash Flows of the Company and Consolidated SCE&G have been reclassified to conform to the current period presentation. Specifically, $81 million of non-cash changes in fair value of interest rate swaps has been reclassified from the Derivative financial instruments caption, with offsetting reclassifications of $96 million and $(15) million within changes in the Regulatory assets and changes in Other liabilities captions, respectively. Additionally, due to insignificance, the captions for changes in Interest accrued and changes in Pension and other postretirement benefits which were utilized in the reconciliation for the prior period have been eliminated and their amounts included within changes in Other liabilities. These reclassifications had no effect on Net Cash Provided From Operating Activities or on any other subtotal in the Condensed Consolidated Statements of Cash Flows.

New Accounting Matters

In May 2014, the FASB issued accounting guidance for revenue arising from contracts with customers that supersedes most current revenue recognition guidance, including industry-specific guidance. This revenue recognition model provides a

five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the

transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive

in exchange for those goods or services. This guidance must be adopted no later than the first quarter of 2018, and early

adoption is permitted in the first quarter of 2017. Adoption using a retrospective method is required, with options to elect

certain practical expedients or to recognize a cumulative effect in the year of initial adoption. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what practical expedients will be elected. The Company and Consolidated SCE&G have not determined the impact this guidance will have on their respective financial statements.

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. This guidance was adopted in the first quarter of 2016 and had no impact on the Company’s or Consolidated SCE&G's financial statements.

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 and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2017. The Company and Consolidated SCE&G are evaluating this guidance and have not determined what impact it will have on their respective financial statements.

In January 2016, the FASB issued accounting guidance intended to clarify the classification and measurement of financial instruments and financial liabilities, among other things. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018. The Company and Consolidated SCE&G are evaluating this guidance and have not determined what impact it will have on their respective financial statements.

In February 2016, the FASB issued accounting guidance related to the recognition, measurement and presentation of

leases. The guidance applies a right-of-use model and, for lessees, requires all leases with a duration over twelve months to be

recorded on the balance sheet, with the rights of use treated as assets and the payment obligations treated as liabilities. Further,

and without consideration of any regulatory accounting requirements which may apply, depending primarily of the nature of the

assets and the relative consumption of them, lease costs will be recognized either through the separate amortization of the right-of-use asset and the recognition of the interest cost related to the payment obligation, or through the recording of a combined

straight-line rental expense. For lessors, the guidance calls for the recognition of income either through the derecognition of

assets and subsequent recording of interest income on lease amounts receivable, or through the recognition of rental income on

a straight line basis, also depending on the nature of the assets and relative consumption. The guidance will be effective for

years beginning in 2019. The Company and Consolidated SCE&G have not determined what impact this guidance will have on their respective financial statements.

In March 2016, the FASB issued accounting guidance changing how companies account for certain aspects of share-based payments to employees. Entities will be required to recognize the income tax effects of awards in the income statement when the awards vest or are settled. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2017. The Company and Consolidated SCE&G are evaluating this guidance and have not determined what impact it will have on their respective financial statements.

XML

RATE AND OTHER REGULATORY MATTERS

3 Months Ended

Mar. 31, 2016

Rate Matters [Line Items]

Public Utilities Disclosure [Text Block]

RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric - Cost of Fuel

By order dated July 15, 2015, the SCPSC approved a settlement agreement among SCE&G and certain other parties concerning SCE&G's petition for approval to participate in a DER program and to recover DER program costs as a separate component of SCE&G's overall fuel factor. Under this order, SCE&G will, among other things, implement programs to encourage the development of renewable energy facilities with a total nameplate capacity of at least approximately 84.5 MW by the end of 2020, of which half is to be customer-scale solar capacity and half is to be utility-scale solar capacity. SCE&G is to make a good faith effort to have at least 30 MW of utility-scale solar capacity in service by the end of 2016.

By Order dated April 29, 2016, the SCPSC approved a settlement agreement among SCE&G, ORS and certain other parties to decrease the total fuel cost component of retail electric rates. SCE&G will reduce the total fuel cost component of retail electric rates to reflect lower projected fuel costs and to eliminate over-collected balances of approximately $61 million for base fuel and environmental costs over a 12-month period beginning with the first billing cycle of May 2016. SCE&G will also recover projected DER program costs of $6.9 million beginning with the first billing cycle of May 2016.

Electric - Base Rates

Pursuant to a 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 months ended March 31, 2016 totaled $3.1 million, and during the three months ended March 31, 2015 totaled $1.9 million. SCE&G anticipates that when the New Units are placed in service and accelerated tax depreciation is recognized on them, these deferred income tax assets will decline. When these deferred income tax assets are fully offset by related deferred income tax liabilities, the carrying cost accruals will cease, and the regulatory asset will begin to be amortized.

By Order dated April 29, 2016, the SCPSC approved SCE&G’s request to increase its pension costs component rider. This pension rider is subject to an annual true-up, depending on conditions in financial markets and other factors. The adjustment is designed to allow SCE&G to recover projected pension costs, including under-collections, over a 12-month period, beginning with the first billing cycle in May 2016.

In April 2016, ORS filed a report arising from its review of SCE&G’s annual DSM Programs rate rider filing. ORS concluded the updated DSM Programs rider proposal was developed in accordance with terms and conditions approved by the SCPSC in prior orders and recommended that SCE&G's request be approved. In addition, ORS recommended SCE&G update the three-year planning models used to calculate the overall effectiveness of the DSM Programs for future program years. By Order dated April 29, 2016, the SCPSC accepted ORS's recommendations and approved SCE&G's request to recover $37.6 million of costs and net lost revenues associated with the DSM Programs.

Gas - PSNC Energy

On March 31, 2016, PSNC Energy filed a general rate case application with the NCUC requesting a general rate increase of approximately $41.6 million, or approximately 9.7%, in annual revenue. The rate increase is largely associated with recovering costs related to expanding and operating PSNC Energy's pipeline system. In its application, PSNC Energy is also requesting approval of a rider to its rates to track and provide for ongoing recovery of capital expenditures related to PSNC Energy’s transmission and distribution pipeline integrity management programs. A hearing on the application is scheduled for the week of August 29, 2016.

Regulatory Assets and Regulatory Liabilities

Rate-regulated utilities recognize in their financial statements certain revenues and expenses in different periods than do other enterprises.  As a result, the Company and Consolidated SCE&G have recorded regulatory assets and regulatory liabilities which are summarized in the following tables. Other than unrecovered plant, substantially all regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities.

	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2016		December 31, 2015		March 31, 2016		December 31, 2015
Regulatory Assets:
Accumulated deferred income taxes	$	297	$	298	$	290	$	291
Environmental remediation costs	41		42		34		35
AROs and related funding	402		405		381		384
Deferred employee benefit plan costs	323		325		293		295
Deferred losses on interest rate derivatives	666		535		666		535
Unrecovered plant	125		127		125		127
DSM Programs	61		61		61		61
Other	153		144		136		129
Total Regulatory Assets	$	2,068	$	1,937	$	1,986	$	1,857

Regulatory Liabilities:
Asset removal costs	$	739	$	732	$	522	$	519
Deferred gains on interest rate derivatives	81		96		81		96
Other	27		27		20		20
Total Regulatory Liabilities	$	847	$	855	$	623	$	635

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.

Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by the Company or Consolidated 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.

Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under GAAP. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. Accordingly, in 2013 SCE&G began recovering through utility rates approximately $63 million of deferred pension costs for electric operations over approximately 30 years and approximately $14 million of deferred pension costs for gas operations over approximately 14 years. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees, or up to approximately 12 years.

Deferred losses or gains on interest rate derivatives represent (i) the effective portions of changes in fair value and payments made or received upon settlement of certain interest rate derivatives designated as cash flow hedges and (ii) the changes in fair value and payments made or received upon settlement of certain other interest rate derivatives not so designated. The amounts recorded with respect to (i) are expected to be amortized to interest expense over the lives of the underlying debt through 2043. The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense through 2065 except when, in the case of deferred gains, such amounts are applied otherwise at the direction of the SCPSC.

Unrecovered plant represents the carrying value of coal-fired generating units, including related materials and supplies inventory, retired from service prior to being fully depreciated. Pursuant to SCPSC approval, SCE&G will amortize these amounts through cost of service rates over the units' previous estimated remaining useful lives through approximately 2025. Unamortized amounts are included in rate base and are earning a current return.

DSM Programs represent SCE&G's deferred costs associated with such programs, and such deferred costs are currently being recovered over approximately five years through an approved rate rider. 

Various other regulatory assets are expected to be recovered in rates over periods of up to approximately 30 years.

Asset removal costs represent estimated net collections through depreciation rates of amounts to be incurred for the removal of assets in the future.

The SCPSC, the NCUC or the FERC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other regulatory assets include, but are not limited to, certain costs which have not been specifically approved for recovery by the SCPSC, the NCUC or by the FERC. In recording such costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders. The costs are currently not being recovered, but are expected to be recovered through rates in future periods. In the future, as a result of deregulation or other changes in the regulatory environment or changes in accounting requirements, the Company or Consolidated SCE&G could be required to write off its regulatory assets and liabilities. Such an event could have a material effect on the Company's and Consolidated SCE&G's financial statements in the period the write-off would be recorded.

SCEG

Rate Matters [Line Items]

Public Utilities Disclosure [Text Block]

RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric - Cost of Fuel

By order dated July 15, 2015, the SCPSC approved a settlement agreement among SCE&G and certain other parties concerning SCE&G's petition for approval to participate in a DER program and to recover DER program costs as a separate component of SCE&G's overall fuel factor. Under this order, SCE&G will, among other things, implement programs to encourage the development of renewable energy facilities with a total nameplate capacity of at least approximately 84.5 MW by the end of 2020, of which half is to be customer-scale solar capacity and half is to be utility-scale solar capacity. SCE&G is to make a good faith effort to have at least 30 MW of utility-scale solar capacity in service by the end of 2016.

By Order dated April 29, 2016, the SCPSC approved a settlement agreement among SCE&G, ORS and certain other parties to decrease the total fuel cost component of retail electric rates. SCE&G will reduce the total fuel cost component of retail electric rates to reflect lower projected fuel costs and to eliminate over-collected balances of approximately $61 million for base fuel and environmental costs over a 12-month period beginning with the first billing cycle of May 2016. SCE&G will also recover projected DER program costs of $6.9 million beginning with the first billing cycle of May 2016.

Electric - Base Rates

Pursuant to a 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 months ended March 31, 2016 totaled $3.1 million, and during the three months ended March 31, 2015 totaled $1.9 million. SCE&G anticipates that when the New Units are placed in service and accelerated tax depreciation is recognized on them, these deferred income tax assets will decline. When these deferred income tax assets are fully offset by related deferred income tax liabilities, the carrying cost accruals will cease, and the regulatory asset will begin to be amortized.

By Order dated April 29, 2016, the SCPSC approved SCE&G’s request to increase its pension costs component rider. This pension rider is subject to an annual true-up, depending on conditions in financial markets and other factors. The adjustment is designed to allow SCE&G to recover projected pension costs, including under-collections, over a 12-month period, beginning with the first billing cycle in May 2016.

In April 2016, ORS filed a report arising from its review of SCE&G’s annual DSM Programs rate rider filing. ORS concluded the updated DSM Programs rider proposal was developed in accordance with terms and conditions approved by the SCPSC in prior orders and recommended that SCE&G's request be approved. In addition, ORS recommended SCE&G update the three-year planning models used to calculate the overall effectiveness of the DSM Programs for future program years. By Order dated April 29, 2016, the SCPSC accepted ORS's recommendations and approved SCE&G's request to recover $37.6 million of costs and net lost revenues associated with the DSM Programs.

Gas - PSNC Energy

On March 31, 2016, PSNC Energy filed a general rate case application with the NCUC requesting a general rate increase of approximately $41.6 million, or approximately 9.7%, in annual revenue. The rate increase is largely associated with recovering costs related to expanding and operating PSNC Energy's pipeline system. In its application, PSNC Energy is also requesting approval of a rider to its rates to track and provide for ongoing recovery of capital expenditures related to PSNC Energy’s transmission and distribution pipeline integrity management programs. A hearing on the application is scheduled for the week of August 29, 2016.

Regulatory Assets and Regulatory Liabilities

Rate-regulated utilities recognize in their financial statements certain revenues and expenses in different periods than do other enterprises.  As a result, the Company and Consolidated SCE&G have recorded regulatory assets and regulatory liabilities which are summarized in the following tables. Other than unrecovered plant, substantially all regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities.

	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2016		December 31, 2015		March 31, 2016		December 31, 2015
Regulatory Assets:
Accumulated deferred income taxes	$	297	$	298	$	290	$	291
Environmental remediation costs	41		42		34		35
AROs and related funding	402		405		381		384
Deferred employee benefit plan costs	323		325		293		295
Deferred losses on interest rate derivatives	666		535		666		535
Unrecovered plant	125		127		125		127
DSM Programs	61		61		61		61
Other	153		144		136		129
Total Regulatory Assets	$	2,068	$	1,937	$	1,986	$	1,857

Regulatory Liabilities:
Asset removal costs	$	739	$	732	$	522	$	519
Deferred gains on interest rate derivatives	81		96		81		96
Other	27		27		20		20
Total Regulatory Liabilities	$	847	$	855	$	623	$	635

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.

Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by the Company or Consolidated 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.

Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under GAAP. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. Accordingly, in 2013 SCE&G began recovering through utility rates approximately $63 million of deferred pension costs for electric operations over approximately 30 years and approximately $14 million of deferred pension costs for gas operations over approximately 14 years. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees, or up to approximately 12 years.

Deferred losses or gains on interest rate derivatives represent (i) the effective portions of changes in fair value and payments made or received upon settlement of certain interest rate derivatives designated as cash flow hedges and (ii) the changes in fair value and payments made or received upon settlement of certain other interest rate derivatives not so designated. The amounts recorded with respect to (i) are expected to be amortized to interest expense over the lives of the underlying debt through 2043. The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense through 2065 except when, in the case of deferred gains, such amounts are applied otherwise at the direction of the SCPSC.

Unrecovered plant represents the carrying value of coal-fired generating units, including related materials and supplies inventory, retired from service prior to being fully depreciated. Pursuant to SCPSC approval, SCE&G will amortize these amounts through cost of service rates over the units' previous estimated remaining useful lives through approximately 2025. Unamortized amounts are included in rate base and are earning a current return.

DSM Programs represent SCE&G's deferred costs associated with such programs, and such deferred costs are currently being recovered over approximately five years through an approved rate rider. 

Various other regulatory assets are expected to be recovered in rates over periods of up to approximately 30 years.

Asset removal costs represent estimated net collections through depreciation rates of amounts to be incurred for the removal of assets in the future.

The SCPSC, the NCUC or the FERC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other regulatory assets include, but are not limited to, certain costs which have not been specifically approved for recovery by the SCPSC, the NCUC or by the FERC. In recording such costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders. The costs are currently not being recovered, but are expected to be recovered through rates in future periods. In the future, as a result of deregulation or other changes in the regulatory environment or changes in accounting requirements, the Company or Consolidated SCE&G could be required to write off its regulatory assets and liabilities. Such an event could have a material effect on the Company's and Consolidated SCE&G's financial statements in the period the write-off would be recorded.

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COMMON EQUITY

3 Months Ended

Mar. 31, 2016

Schedule of Capitalization, Equity [Line Items]

Stockholders' Equity Note Disclosure [Text Block]

SCANA had 200 million shares of common stock authorized as of March 31, 2016 and December 31, 2015. Gains and losses on cash flow hedges reclassified during the three months ended March 31, 2016 resulted in higher interest expense of $2 million and higher cost of gas purchased for resale of $5 million. Such reclassifications during the comparable period in 2015 resulted in higher interest expense of $2 million and higher cost of gas purchased for resale of $7 million.

SCEG

Schedule of Capitalization, Equity [Line Items]

Stockholders' Equity Note Disclosure [Text Block]

Authorized shares of SCE&G common stock were 50 million as of March 31, 2016 and December 31, 2015. Authorized shares of SCE&G preferred stock were 20 million, of which 1,000 shares, no par value, were issued and outstanding as of March 31, 2016 and December 31, 2015. All issued and outstanding shares of SCE&G's common and preferred stock are held by SCANA.

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LONG-TERM AND SHORT-TERM DEBT

3 Months Ended

Mar. 31, 2016

Debt Instrument [Line Items]

Long-term Debt [Text Block]

LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

Substantially all electric utility plant is pledged as collateral in connection with long-term debt.

Liquidity

Credit agreements are used for general corporate purposes, including liquidity support for each company's commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, certain fossil fuels, and emission and other environmental allowances. Committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Committed LOC, outstanding LOC advances, commercial paper, and LOC-supported letter of credit obligations were as follows: 

	March 31, 2016
Millions of dollars	Total		SCANA			Consolidated SCE&G			PSNC  Energy
Lines of credit:
Five-year, expiring December 2020	$	1,300	$	400		$	700		$	200
Fuel Company five-year, expiring December 2020	$	500	—			$	500		—
Three-year, expiring December 2018	$	200	—			$	200		—
Total committed long-term	$	2,000	$	400		$	1,400		$	200
Outstanding commercial paper (270 or fewer days)	$	917	$	10		$	870		$	37
Weighted average interest rate			0.90		%	0.83		%	0.81		%
Letters of credit supported by LOC	$	3.3	$	3		$	0.3		—
Available	$	1,080	$	387		$	530		$	163

	December 31, 2015
Millions of dollars	Total		SCANA			Consolidated SCE&G			PSNC  Energy
Lines of credit:
Five-year, expiring December 2020	$	1,300	$	400		$	700		$	200
Fuel Company five-year, expiring December 2020	$	500	—			$	500		—
Three-year, expiring December 2018	$	200	—			$	200		—
Total committed long-term	$	2,000	$	400		$	1,400		$	200
Outstanding commercial paper (270 or fewer days)	$	531	$	37		$	420		$	74
Weighted average interest rate			1.19		%	0.74		%	0.77		%
Letters of credit supported by LOC	$	3.3	$	3		$	0.3		—
Available	$	1,466	$	360		$	980		$	126

Each of the Company and Consolidated SCE&G is obligated with respect to an aggregate of $67.8 million of industrial revenue bonds which are secured by letters of credit issued by TD Bank N.A. These letters of credit expire, subject to renewal, in the fourth quarter of 2019.

    Consolidated SCE&G participates in a utility money pool with SCANA and another regulated subsidiary of SCANA. Money pool borrowings and investments bear interest at short-term market rates. Consolidated SCE&G’s interest income and expense from money pool transactions were not significant for any period presented. At March 31, 2016, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $43.9 million. At December 31, 2015, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $33.0 million and money pool investments due from an affiliate of $9.0 million. On Consolidated SCE&G's balance sheets, amounts due from an affiliate are included within Receivables-affiliated companies, and amounts due to an affiliate are included within Affiliated payables.

SCEG

Debt Instrument [Line Items]

Long-term Debt [Text Block]

LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

Substantially all electric utility plant is pledged as collateral in connection with long-term debt.

Liquidity

Credit agreements are used for general corporate purposes, including liquidity support for each company's commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, certain fossil fuels, and emission and other environmental allowances. Committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Committed LOC, outstanding LOC advances, commercial paper, and LOC-supported letter of credit obligations were as follows: 

	March 31, 2016
Millions of dollars	Total		SCANA			Consolidated SCE&G			PSNC  Energy
Lines of credit:
Five-year, expiring December 2020	$	1,300	$	400		$	700		$	200
Fuel Company five-year, expiring December 2020	$	500	—			$	500		—
Three-year, expiring December 2018	$	200	—			$	200		—
Total committed long-term	$	2,000	$	400		$	1,400		$	200
Outstanding commercial paper (270 or fewer days)	$	917	$	10		$	870		$	37
Weighted average interest rate			0.90		%	0.83		%	0.81		%
Letters of credit supported by LOC	$	3.3	$	3		$	0.3		—
Available	$	1,080	$	387		$	530		$	163

	December 31, 2015
Millions of dollars	Total		SCANA			Consolidated SCE&G			PSNC  Energy
Lines of credit:
Five-year, expiring December 2020	$	1,300	$	400		$	700		$	200
Fuel Company five-year, expiring December 2020	$	500	—			$	500		—
Three-year, expiring December 2018	$	200	—			$	200		—
Total committed long-term	$	2,000	$	400		$	1,400		$	200
Outstanding commercial paper (270 or fewer days)	$	531	$	37		$	420		$	74
Weighted average interest rate			1.19		%	0.74		%	0.77		%
Letters of credit supported by LOC	$	3.3	$	3		$	0.3		—
Available	$	1,466	$	360		$	980		$	126

Each of the Company and Consolidated SCE&G is obligated with respect to an aggregate of $67.8 million of industrial revenue bonds which are secured by letters of credit issued by TD Bank N.A. These letters of credit expire, subject to renewal, in the fourth quarter of 2019.

    Consolidated SCE&G participates in a utility money pool with SCANA and another regulated subsidiary of SCANA. Money pool borrowings and investments bear interest at short-term market rates. Consolidated SCE&G’s interest income and expense from money pool transactions were not significant for any period presented. At March 31, 2016, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $43.9 million. At December 31, 2015, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $33.0 million and money pool investments due from an affiliate of $9.0 million. On Consolidated SCE&G's balance sheets, amounts due from an affiliate are included within Receivables-affiliated companies, and amounts due to an affiliate are included within Affiliated payables.

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INCOME TAXES

3 Months Ended

Mar. 31, 2016

income tax [Line Items]

Income Tax Disclosure [Text Block]

INCOME TAXES

Consolidated SCE&G is included in the consolidated federal income tax returns of SCANA and files various applicable state and local income tax returns.

During 2013 and 2014, SCANA amended certain of its tax returns to claim certain tax-defined research and development deductions and credits and its related impact on domestic production activities. SCANA also made similar claims in filing its 2013 and 2014 returns in 2014 and 2015, respectively. In connection with these federal and state filings, the Company and Consolidated SCE&G recorded an unrecognized tax benefit of $49 million. If recognized, $17 million of the tax benefit would affect the Company’s and Consolidated SCE&G's effective tax rate. It is reasonably possible that these tax benefits will increase by an additional $7 million within the next 12 months. It is also reasonably possible that these tax benefits may decrease by $8 million within the next 12 months. No other material changes in the status of the Company’s or Consolidated SCE&G's tax positions have occurred through March 31, 2016.

The Company and Consolidated SCE&G recognize interest accrued related to unrecognized tax benefits within interest expense or interest income and recognize tax penalties within other expenses.  Amounts recorded for such interest income, interest expense or tax penalties have not been material.

SCEG

income tax [Line Items]

Income Tax Disclosure [Text Block]

INCOME TAXES

Consolidated SCE&G is included in the consolidated federal income tax returns of SCANA and files various applicable state and local income tax returns.

During 2013 and 2014, SCANA amended certain of its tax returns to claim certain tax-defined research and development deductions and credits and its related impact on domestic production activities. SCANA also made similar claims in filing its 2013 and 2014 returns in 2014 and 2015, respectively. In connection with these federal and state filings, the Company and Consolidated SCE&G recorded an unrecognized tax benefit of $49 million. If recognized, $17 million of the tax benefit would affect the Company’s and Consolidated SCE&G's effective tax rate. It is reasonably possible that these tax benefits will increase by an additional $7 million within the next 12 months. It is also reasonably possible that these tax benefits may decrease by $8 million within the next 12 months. No other material changes in the status of the Company’s or Consolidated SCE&G's tax positions have occurred through March 31, 2016.

The Company and Consolidated SCE&G recognize interest accrued related to unrecognized tax benefits within interest expense or interest income and recognize tax penalties within other expenses.  Amounts recorded for such interest income, interest expense or tax penalties have not been material.

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DERIVATIVE FINANCIAL INSTRUMENTS

3 Months Ended

Mar. 31, 2016

Derivative [Line Items]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

6. DERIVATIVE FINANCIAL INSTRUMENTS

Derivative instruments are recognized either as assets or liabilities in the statement of financial position and are measured at fair value. Changes in the fair value of derivative instruments are recognized either in earnings, as a component of other comprehensive income (loss) or, for regulated operations, within regulatory assets or regulatory liabilities, depending upon the intended use of the derivative and the resulting designation. 

Policies and procedures and risk limits are established to control the level of market, credit, liquidity and operational and administrative risks.  SCANA’s Board of Directors has delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and oversee and review the risk management process and infrastructure for SCANA and each of its subsidiaries.  The Risk Management Committee, which is comprised of certain officers, including the Risk Management Officer and other senior officers, apprises the Audit Committee of the Board of Directors with regard to the management of risk and brings to their attention significant areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions.

Commodity Derivatives

The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types.  Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations. Instruments designated as fair value hedges are used to mitigate exposure to fluctuating market prices created by fixed prices of stored natural gas.  The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy companies and financial institutions.  Cash settlements of commodity derivatives are classified as operating activities in the 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

Interest rate swaps may be used to manage interest rate risk and exposure to changes in fair value attributable to changes in interest rates on certain debt issuances.  In cases where swaps that are designated as cash flow hedges are used to synthetically convert variable rate debt to fixed rate debt, periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense.

Treasury rate lock or forward starting swap agreements that are designated as cash flow hedges may be used in anticipation of the issuance of debt.  Except as described in the following paragraph, the effective portions of changes in fair value and payments made or received upon termination of such agreements for regulated subsidiaries are recorded in regulatory assets or regulatory liabilities. For SCANA and the nonregulated subsidiaries, such amounts are recorded in AOCI. Such amounts are amortized to interest expense over the term of the underlying debt. Ineffective portions of fair value changes are recognized in income.

Pursuant to regulatory orders, interest rate derivatives entered into by SCE&G after October 2013 are not designated as cash flow hedges and fair value changes and settlement amounts are recorded as regulatory assets and liabilities. Settlement losses on swaps will be amortized over the lives of subsequent debt issuances and gains may be applied to under-collected fuel, may be amortized to interest expense or may be applied as otherwise directed by the SCPSC.

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)
		Retail Gas
Hedge designation	Gas Distribution	Marketing	Energy Marketing	Total
As of March 31, 2016
Commodity contracts	9,240,000	6,236,000	4,632,500	20,108,500
Energy management contracts (a)	—	—	30,994,204	30,994,204
Total (a)	9,240,000	6,236,000	35,626,704	51,102,704
As of December 31, 2015
Commodity contracts	7,530,000	7,869,000	3,973,500	19,372,500
Energy management contracts (b)	—	—	38,857,480	38,857,480
Total (b)	7,530,000	7,869,000	42,830,980	58,229,980

(a)  Includes an aggregate 1,679,289 MMBTU related to basis swap contracts in Energy Marketing.

(b)  Includes an aggregate 1,842,048 MMBTU related to basis swap contracts in Energy Marketing.

The aggregate notional amounts of the interest rate swaps were as follows:

Interest Rate Swaps
	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2016		December 31, 2015		March 31, 2016		December 31, 2015
Designated as hedging instruments	$	120.0	$	120.0	$	36.4	$	36.4
Not designated as hedging instruments	1,235.0		1,235.0		1,235.0		1,235.0

The following table shows the fair value and balance sheet location of derivative instruments. Although derivatives subject to master netting arrangements are netted on the Consolidated Balance Sheet, the fair values presented below are shown gross and cash collateral on the derivatives has not been netted against the fair values shown.

Fair Values of Derivative Instruments
		The Company				Consolidated SCE&G
Millions of dollars	Balance Sheet Location	Asset		Liability		Asset		Liability
As of March 31, 2016
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	3			$	1
	Other deferred credits and other liabilities			36				12
Commodity contracts
	Other current assets	$	1	1
	Derivative financial instruments			2
Total		$	1	$	42	—		$	13
Not designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	100			$	100
	Other deferred credits and other liabilities			83				83
Commodity contracts
	Other current assets	$	2
Energy management contracts
	Other current assets	9		1
	Other deferred debits and other assets	4
	Derivative financial instruments			9
	Other deferred credits and other liabilities			3
Total		$	15	$	196	—		$	183
As of December 31, 2015
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	4			$	1
	Other deferred credits and other liabilities			28				9
Commodity contracts
	Other current assets			1
	Derivative financial instruments			4
Total		$	—	$	37	—		$	10
Not designated as hedging instruments
Interest rate contracts
	Other current assets	$	10			$	10
	Other deferred debits and other assets	5				5
	Derivative financial instruments			$	33			$	33
	Other deferred credits and other liabilities			22				22
Commodity contracts
	Other current assets	1		2
Energy management contracts
	Other current assets	11
	Other deferred debits and other assets	3
	Derivative financial instruments			9
	Other deferred credits and other liabilities			3
Total		$	30	$	69	$	15	$	55

 The effect of derivative instruments on the condensed consolidated statements of income is as follows: 

Derivatives in Cash Flow Hedging Relationships

The Company and Consolidated SCE&G:
	Loss Deferred in Regulatory Accounts							Loss Reclassified from Deferred Accounts into Income
	(Effective Portion)							(Effective Portion)
Millions of dollars	2016			2015			Location	2016			2015
Three Months Ended March 31,
Interest rate contracts	$	(3	)	$	(2	)	Interest expense	$	(1	)	$	—

The Company:
	Loss Recognized in OCI, net of tax							Loss Reclassified from AOCI into Income, net of tax
	(Effective Portion)							(Effective Portion)
Millions of dollars	2016			2015			Location	2016			2015
Three Months Ended March 31,
Interest rate contracts	$	(3	)	$	(2	)	Interest expense	$	(2	)	$	(2	)
Commodity contracts	(2		)	(1		)	Gas purchased for resale	(5		)	(7		)
Total	$	(5	)	$	(3	)		$	(7	)	$	(9	)

As of March 31, 2016, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $1.1 million as an increase to gas cost, assuming natural gas markets remain at their current levels, and approximately $6.5 million as an increase to interest expense.  As of March 31, 2016, all of the Company’s commodity cash flow hedges settle by their terms before the end of the first quarter of 2019.

As of March 31, 2016, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $2.1 million as an increase to interest expense.

Hedge Ineffectiveness

For the Company and Consolidated SCE&G, ineffectiveness on interest rate hedges designated as cash flow hedges was insignificant during all periods presented.

Derivatives not designated as Hedging Instruments
The Company and Consolidated SCE&G:
	Loss Deferred in Regulatory Accounts							Gain Reclassified from Deferred Accounts into Income
Millions of dollars	2016			2015			Location	2016		2015
Three Months Ended March 31,
Interest rate contracts	$	(144	)	$	(94	)	Other income	$	—	$	4

As of March 31, 2016, the Company and Consolidated SCE&G expect that during the next 12 months reclassifications from regulatory accounts to earnings arising from derivatives not designated as hedges will include $0.7 million as an increase to interest expense.

Credit Risk Considerations

Certain derivative contracts contain contingent credit features. These features may include (i) material adverse change clauses or payment acceleration clauses that could result in immediate payments or (ii) the posting of letters of credit or termination of the derivative contract before maturity if specific events occur, such as a credit rating downgrade below investment grade or failure to post collateral.

Derivative Contracts with Credit Contingent Features
	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2016		December 31, 2015		March 31, 2016		December 31, 2015
in Net Liability Position
Aggregate fair value of derivatives in net liability position	$	234.1	$	95.2	$	196.1	$	57.0
Fair value of collateral already posted	124.1		50.4		88.2		13.4
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	110.0		44.8		107.9		43.6
in Net Asset Position
Aggregate fair value of derivatives in net asset position	$	—	$	7.3	$	—	$	7.3
Fair value of collateral already posted	—		—		—		—
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	—		7.3		—		7.3

In addition, for fixed price supply contracts offered to certain of SEMI's customers, the Company could have called on letters of credit in the amount of $3.0 million related to $13.0 million in commodity derivatives that are in a net asset position at March 31, 2016, compared to letters of credit of $3.0 million related to derivatives of $14.0 million at December 31, 2015, if all the contingent features underlying these instruments had been fully triggered.

Information related to the offsetting of derivative assets follows:

Derivative Assets	The Company												Consolidated SCE&G
Millions of dollars	Interest Rate Contracts			Commodity Contracts			Energy Management Contracts			Total			Interest Rate Contracts
As of March 31, 2016
Gross Amounts of Recognized Assets	—			$	3		$	13		$	16		—
Gross Amounts Offset in Statement of Financial Position	—			(1		)	—			(1		)	—
Net Amounts Presented in Statement of Financial Position	—			2			13			15			—
Gross Amounts Not Offset - Financial Instruments	—			—			—			—			—
Gross Amounts Not Offset - Cash Collateral Received	—			—			—			—			—
Net Amount	—			$	2		$	13		$	15		—
Balance sheet location
Other current assets										$	11		—
Other deferred debits and other assets										4			—
Total										$	15		—
As of December 31, 2015
Gross Amounts of Recognized Assets	$	15		$	1		$	15		$	31		$	15
Gross Amounts Offset in Statement of Financial Position	—			—			(1		)	(1		)	—
Net Amounts Presented in Statement of Financial Position	15			1			14			30			15
Gross Amounts Not Offset - Financial Instruments	(8		)	—			—			(8		)	(8		)
Gross Amounts Not Offset - Cash Collateral Received	—			—			—			—			—
Net Amount	$	7		$	1		$	14		$	22		$	7
Balance sheet location
Other current assets										$	22		$	10
Other deferred debits and other assets										8			5
Total										$	30		$	15

Information related to the offsetting of derivative liabilities follows:

Derivative Liabilities	The Company												Consolidated SCE&G
Millions of dollars	Interest Rate Contracts			Commodity Contracts			Energy Management Contracts			Total			Interest Rate Contracts
As of March 31, 2016
Gross Amounts of Recognized Liabilities	$	222		$	3		$	13		$	238		$	196
Gross Amounts Offset in Statement of Financial Position	—			(1		)	—			(1		)	—
Net Amounts Presented in Statement of Financial Position	222			2			13			237			196
Gross Amounts Not Offset - Financial Instruments	—			—			—			—			—
Gross Amounts Not Offset - Cash Collateral Posted	(116		)	(2		)	(6		)	(124		)	(88		)
Net Amount	$	106		$	—		$	7		$	113		$	108
Balance sheet location
Other current assets										$	2		—
Derivative financial instruments										113			$	101
Other deferred credits and other liabilities										122			95
Total										$	237		$	196
As of December 31, 2015
Gross Amounts of Recognized Liabilities	$	87		$	5		$	15		$	107		$	65
Gross Amounts Offset in Statement of Financial Position	—			—			(1		)	(1		)	—
Net Amounts Presented in Statement of Financial Position	87			5			14			106			65
Gross Amounts Not Offset - Financial Instruments	(8		)	—			—			(8		)	(8		)
Gross Amounts Not Offset - Cash Collateral Posted	(36		)	(5		)	(9		)	(50		)	(13		)
Net Amount	$	43		$	—		$	5		$	48		$	44
Balance sheet location
Other current assets										$	3		—
Derivative financial instruments										50			$	34
Other deferred credits and other liabilities										53			31
Total										$	106		$	65

SCEG

Derivative [Line Items]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

DERIVATIVE FINANCIAL INSTRUMENTS

Derivative instruments are recognized either as assets or liabilities in the statement of financial position and are measured at fair value. Changes in the fair value of derivative instruments are recognized either in earnings, as a component of other comprehensive income (loss) or, for regulated operations, within regulatory assets or regulatory liabilities, depending upon the intended use of the derivative and the resulting designation. 

Policies and procedures and risk limits are established to control the level of market, credit, liquidity and operational and administrative risks.  SCANA’s Board of Directors has delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and oversee and review the risk management process and infrastructure for SCANA and each of its subsidiaries.  The Risk Management Committee, which is comprised of certain officers, including the Risk Management Officer and other senior officers, apprises the Audit Committee of the Board of Directors with regard to the management of risk and brings to their attention significant areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions.

Commodity Derivatives

The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types.  Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations. Instruments designated as fair value hedges are used to mitigate exposure to fluctuating market prices created by fixed prices of stored natural gas.  The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy companies and financial institutions.  Cash settlements of commodity derivatives are classified as operating activities in the 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

Interest rate swaps may be used to manage interest rate risk and exposure to changes in fair value attributable to changes in interest rates on certain debt issuances.  In cases where swaps that are designated as cash flow hedges are used to synthetically convert variable rate debt to fixed rate debt, periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense.

Treasury rate lock or forward starting swap agreements that are designated as cash flow hedges may be used in anticipation of the issuance of debt.  Except as described in the following paragraph, the effective portions of changes in fair value and payments made or received upon termination of such agreements for regulated subsidiaries are recorded in regulatory assets or regulatory liabilities. For SCANA and the nonregulated subsidiaries, such amounts are recorded in AOCI. Such amounts are amortized to interest expense over the term of the underlying debt. Ineffective portions of fair value changes are recognized in income.

Pursuant to regulatory orders, interest rate derivatives entered into by SCE&G after October 2013 are not designated as cash flow hedges and fair value changes and settlement amounts are recorded as regulatory assets and liabilities. Settlement losses on swaps will be amortized over the lives of subsequent debt issuances and gains may be applied to under-collected fuel, may be amortized to interest expense or may be applied as otherwise directed by the SCPSC.

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)
		Retail Gas
Hedge designation	Gas Distribution	Marketing	Energy Marketing	Total
As of March 31, 2016
Commodity contracts	9,240,000	6,236,000	4,632,500	20,108,500
Energy management contracts (a)	—	—	30,994,204	30,994,204
Total (a)	9,240,000	6,236,000	35,626,704	51,102,704
As of December 31, 2015
Commodity contracts	7,530,000	7,869,000	3,973,500	19,372,500
Energy management contracts (b)	—	—	38,857,480	38,857,480
Total (b)	7,530,000	7,869,000	42,830,980	58,229,980

(a)  Includes an aggregate 1,679,289 MMBTU related to basis swap contracts in Energy Marketing.

(b)  Includes an aggregate 1,842,048 MMBTU related to basis swap contracts in Energy Marketing.

The aggregate notional amounts of the interest rate swaps were as follows:

Interest Rate Swaps
	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2016		December 31, 2015		March 31, 2016		December 31, 2015
Designated as hedging instruments	$	120.0	$	120.0	$	36.4	$	36.4
Not designated as hedging instruments	1,235.0		1,235.0		1,235.0		1,235.0

The following table shows the fair value and balance sheet location of derivative instruments. Although derivatives subject to master netting arrangements are netted on the Consolidated Balance Sheet, the fair values presented below are shown gross and cash collateral on the derivatives has not been netted against the fair values shown.

Fair Values of Derivative Instruments
		The Company				Consolidated SCE&G
Millions of dollars	Balance Sheet Location	Asset		Liability		Asset		Liability
As of March 31, 2016
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	3			$	1
	Other deferred credits and other liabilities			36				12
Commodity contracts
	Other current assets	$	1	1
	Derivative financial instruments			2
Total		$	1	$	42	—		$	13
Not designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	100			$	100
	Other deferred credits and other liabilities			83				83
Commodity contracts
	Other current assets	$	2
Energy management contracts
	Other current assets	9		1
	Other deferred debits and other assets	4
	Derivative financial instruments			9
	Other deferred credits and other liabilities			3
Total		$	15	$	196	—		$	183
As of December 31, 2015
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	4			$	1
	Other deferred credits and other liabilities			28				9
Commodity contracts
	Other current assets			1
	Derivative financial instruments			4
Total		$	—	$	37	—		$	10
Not designated as hedging instruments
Interest rate contracts
	Other current assets	$	10			$	10
	Other deferred debits and other assets	5				5
	Derivative financial instruments			$	33			$	33
	Other deferred credits and other liabilities			22				22
Commodity contracts
	Other current assets	1		2
Energy management contracts
	Other current assets	11
	Other deferred debits and other assets	3
	Derivative financial instruments			9
	Other deferred credits and other liabilities			3
Total		$	30	$	69	$	15	$	55

 The effect of derivative instruments on the condensed consolidated statements of income is as follows: 

Derivatives in Cash Flow Hedging Relationships

The Company and Consolidated SCE&G:
	Loss Deferred in Regulatory Accounts							Loss Reclassified from Deferred Accounts into Income
	(Effective Portion)							(Effective Portion)
Millions of dollars	2016			2015			Location	2016			2015
Three Months Ended March 31,
Interest rate contracts	$	(3	)	$	(2	)	Interest expense	$	(1	)	$	—

The Company:
	Loss Recognized in OCI, net of tax							Loss Reclassified from AOCI into Income, net of tax
	(Effective Portion)							(Effective Portion)
Millions of dollars	2016			2015			Location	2016			2015
Three Months Ended March 31,
Interest rate contracts	$	(3	)	$	(2	)	Interest expense	$	(2	)	$	(2	)
Commodity contracts	(2		)	(1		)	Gas purchased for resale	(5		)	(7		)
Total	$	(5	)	$	(3	)		$	(7	)	$	(9	)

As of March 31, 2016, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $1.1 million as an increase to gas cost, assuming natural gas markets remain at their current levels, and approximately $6.5 million as an increase to interest expense.  As of March 31, 2016, all of the Company’s commodity cash flow hedges settle by their terms before the end of the first quarter of 2019.

As of March 31, 2016, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $2.1 million as an increase to interest expense.

Hedge Ineffectiveness

For the Company and Consolidated SCE&G, ineffectiveness on interest rate hedges designated as cash flow hedges was insignificant during all periods presented.

Derivatives not designated as Hedging Instruments
The Company and Consolidated SCE&G:
	Loss Deferred in Regulatory Accounts							Gain Reclassified from Deferred Accounts into Income
Millions of dollars	2016			2015			Location	2016		2015
Three Months Ended March 31,
Interest rate contracts	$	(144	)	$	(94	)	Other income	$	—	$	4

As of March 31, 2016, the Company and Consolidated SCE&G expect that during the next 12 months reclassifications from regulatory accounts to earnings arising from derivatives not designated as hedges will include $0.7 million as an increase to interest expense.

Credit Risk Considerations

Certain derivative contracts contain contingent credit features. These features may include (i) material adverse change clauses or payment acceleration clauses that could result in immediate payments or (ii) the posting of letters of credit or termination of the derivative contract before maturity if specific events occur, such as a credit rating downgrade below investment grade or failure to post collateral.

Derivative Contracts with Credit Contingent Features
	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2016		December 31, 2015		March 31, 2016		December 31, 2015
in Net Liability Position
Aggregate fair value of derivatives in net liability position	$	234.1	$	95.2	$	196.1	$	57.0
Fair value of collateral already posted	124.1		50.4		88.2		13.4
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	110.0		44.8		107.9		43.6
in Net Asset Position
Aggregate fair value of derivatives in net asset position	$	—	$	7.3	$	—	$	7.3
Fair value of collateral already posted	—		—		—		—
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	—		7.3		—		7.3

In addition, for fixed price supply contracts offered to certain of SEMI's customers, the Company could have called on letters of credit in the amount of $3.0 million related to $13.0 million in commodity derivatives that are in a net asset position at March 31, 2016, compared to letters of credit of $3.0 million related to derivatives of $14.0 million at December 31, 2015, if all the contingent features underlying these instruments had been fully triggered.

Information related to the offsetting of derivative assets follows:

Derivative Assets	The Company												Consolidated SCE&G
Millions of dollars	Interest Rate Contracts			Commodity Contracts			Energy Management Contracts			Total			Interest Rate Contracts
As of March 31, 2016
Gross Amounts of Recognized Assets	—			$	3		$	13		$	16		—
Gross Amounts Offset in Statement of Financial Position	—			(1		)	—			(1		)	—
Net Amounts Presented in Statement of Financial Position	—			2			13			15			—
Gross Amounts Not Offset - Financial Instruments	—			—			—			—			—
Gross Amounts Not Offset - Cash Collateral Received	—			—			—			—			—
Net Amount	—			$	2		$	13		$	15		—
Balance sheet location
Other current assets										$	11		—
Other deferred debits and other assets										4			—
Total										$	15		—
As of December 31, 2015
Gross Amounts of Recognized Assets	$	15		$	1		$	15		$	31		$	15
Gross Amounts Offset in Statement of Financial Position	—			—			(1		)	(1		)	—
Net Amounts Presented in Statement of Financial Position	15			1			14			30			15
Gross Amounts Not Offset - Financial Instruments	(8		)	—			—			(8		)	(8		)
Gross Amounts Not Offset - Cash Collateral Received	—			—			—			—			—
Net Amount	$	7		$	1		$	14		$	22		$	7
Balance sheet location
Other current assets										$	22		$	10
Other deferred debits and other assets										8			5
Total										$	30		$	15

Information related to the offsetting of derivative liabilities follows:

Derivative Liabilities	The Company												Consolidated SCE&G
Millions of dollars	Interest Rate Contracts			Commodity Contracts			Energy Management Contracts			Total			Interest Rate Contracts
As of March 31, 2016
Gross Amounts of Recognized Liabilities	$	222		$	3		$	13		$	238		$	196
Gross Amounts Offset in Statement of Financial Position	—			(1		)	—			(1		)	—
Net Amounts Presented in Statement of Financial Position	222			2			13			237			196
Gross Amounts Not Offset - Financial Instruments	—			—			—			—			—
Gross Amounts Not Offset - Cash Collateral Posted	(116		)	(2		)	(6		)	(124		)	(88		)
Net Amount	$	106		$	—		$	7		$	113		$	108
Balance sheet location
Other current assets										$	2		—
Derivative financial instruments										113			$	101
Other deferred credits and other liabilities										122			95
Total										$	237		$	196
As of December 31, 2015
Gross Amounts of Recognized Liabilities	$	87		$	5		$	15		$	107		$	65
Gross Amounts Offset in Statement of Financial Position	—			—			(1		)	(1		)	—
Net Amounts Presented in Statement of Financial Position	87			5			14			106			65
Gross Amounts Not Offset - Financial Instruments	(8		)	—			—			(8		)	(8		)
Gross Amounts Not Offset - Cash Collateral Posted	(36		)	(5		)	(9		)	(50		)	(13		)
Net Amount	$	43		$	—		$	5		$	48		$	44
Balance sheet location
Other current assets										$	3		—
Derivative financial instruments										50			$	34
Other deferred credits and other liabilities										53			31
Total										$	106		$	65

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

3 Months Ended

Mar. 31, 2016

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair Value Disclosures [Text Block]

7. FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

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 and Consolidated SCE&G's interest rate swap agreements are valued using discounted cash flow models with independently sourced data. Fair value measurements, and the level within the fair value hierarchyin which the measurements fall, were as follows:

	As of March 31, 2016						As of December 31, 2015
	The Company				Consolidated SCE&G		The Company				Consolidated SCE&G
Millions of dollars	Level 1		Level 2		Level 2		Level 1		Level 2		Level 2
Assets:
Available for sale securities	$	11					$	11
Held to maturity securities			$	7
Interest rate contracts									$	15	$	15
Commodity contracts	2						1
Energy management contracts			13						14
Liabilities:
Interest rate contracts			222		$	196			87		65
Commodity contracts			2				1		4
Energy management contracts	1		13				4		12

The Company had no Level 3 fair value measurements for either period presented, and there were no transfers of fair value amounts into or out of Levels 1, 2 or 3 during the periods presented. Consolidated SCE&G had 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:

Long-Term Debt	March 31, 2016				December 31, 2015
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
The Company	$	5,995.4	$	6,704.5	$	5,997.6	$	6,445.7
Consolidated SCE&G	$	4,766.9	$	5,368.3	$	4,769.0	$	5,129.1

Fair values of long-term debt instruments are based on net present value calculations using independently sourced market data that incorporate a developed discount rate using similarly rated long-term debt, along with benchmark interest rates.  As such, the aggregate fair values presented above are considered to be Level 2. Early settlement of long-term debt may not be possible or may not be considered prudent.

Carrying values of short-term borrowings approximate 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

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 and Consolidated SCE&G's interest rate swap agreements are valued using discounted cash flow models with independently sourced data. Fair value measurements, and the level within the fair value hierarchyin which the measurements fall, were as follows:

	As of March 31, 2016						As of December 31, 2015
	The Company				Consolidated SCE&G		The Company				Consolidated SCE&G
Millions of dollars	Level 1		Level 2		Level 2		Level 1		Level 2		Level 2
Assets:
Available for sale securities	$	11					$	11
Held to maturity securities			$	7
Interest rate contracts									$	15	$	15
Commodity contracts	2						1
Energy management contracts			13						14
Liabilities:
Interest rate contracts			222		$	196			87		65
Commodity contracts			2				1		4
Energy management contracts	1		13				4		12

The Company had no Level 3 fair value measurements for either period presented, and there were no transfers of fair value amounts into or out of Levels 1, 2 or 3 during the periods presented. Consolidated SCE&G had 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:

Long-Term Debt	March 31, 2016				December 31, 2015
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
The Company	$	5,995.4	$	6,704.5	$	5,997.6	$	6,445.7
Consolidated SCE&G	$	4,766.9	$	5,368.3	$	4,769.0	$	5,129.1

Fair values of long-term debt instruments are based on net present value calculations using independently sourced market data that incorporate a developed discount rate using similarly rated long-term debt, along with benchmark interest rates.  As such, the aggregate fair values presented above are considered to be Level 2. Early settlement of long-term debt may not be possible or may not be considered prudent.

Carrying values of short-term borrowings approximate 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.

XML

EMPLOYEE BENEFIT PLANS

3 Months Ended

Mar. 31, 2016

Pension and Other Postretirement Benefit Plans

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS

Components of net periodic benefit cost recorded by the Company and Consolidated SCE&G were as follows: 

The Company	Pension Benefits						Other Postretirement Benefits
	2016			2015			2016		2015
Three months ended March 31,
Service cost	$	5.5		$	5.8		$	1.3	$	1.4
Interest cost	9.9			9.5			3.0		2.9
Expected return on assets	(14.1		)	(15.5		)	—		—
Prior service cost amortization	1.0			1.0			0.1		0.1
Amortization of actuarial losses	3.7			3.5			0.1		0.6
Net periodic benefit cost	$	6.0		$	4.3		$	4.5	$	5.0

Consolidated SCE&G	Pension Benefits						Other Postretirement Benefits
	2016			2015			2016		2015
Three months ended March 31,
Service cost	$	4.5		$	4.6		$	1.0	$	1.1
Interest cost	8.4			8.0			2.5		2.3
Expected return on assets	(11.9		)	(13.0		)	—		—
Prior service cost amortization	0.8			0.8			0.1		0.1
Amortization of actuarial losses	3.1			3.0			0.1		0.4
Net periodic benefit cost	$	4.9		$	3.4		$	3.7	$	3.9

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

Components of net periodic benefit cost recorded by the Company and Consolidated SCE&G were as follows: 

The Company	Pension Benefits						Other Postretirement Benefits
	2016			2015			2016		2015
Three months ended March 31,
Service cost	$	5.5		$	5.8		$	1.3	$	1.4
Interest cost	9.9			9.5			3.0		2.9
Expected return on assets	(14.1		)	(15.5		)	—		—
Prior service cost amortization	1.0			1.0			0.1		0.1
Amortization of actuarial losses	3.7			3.5			0.1		0.6
Net periodic benefit cost	$	6.0		$	4.3		$	4.5	$	5.0

Consolidated SCE&G	Pension Benefits						Other Postretirement Benefits
	2016			2015			2016		2015
Three months ended March 31,
Service cost	$	4.5		$	4.6		$	1.0	$	1.1
Interest cost	8.4			8.0			2.5		2.3
Expected return on assets	(11.9		)	(13.0		)	—		—
Prior service cost amortization	0.8			0.8			0.1		0.1
Amortization of actuarial losses	3.1			3.0			0.1		0.4
Net periodic benefit cost	$	4.9		$	3.4		$	3.7	$	3.9

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.

XML

COMMITMENTS AND CONTINGENCIES

3 Months Ended

Mar. 31, 2016

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 $13.4 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $375 million by ANI with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. Each reactor licensee is currently liable for up to $127.3 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $18.9 million of the liability per reactor would be assessed per year. SCE&G’s maximum assessment, based on its two-thirds ownership of Summer Station Unit 1, would be $84.8 million per incident, but not more than $12.6 million per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years.

SCE&G currently maintains insurance policies (for itself and on behalf of Santee Cooper) with NEIL. The policies provide coverage to Summer Station Unit 1 for property damage and outage costs up to $2.75 billion resulting from an event of nuclear origin and up to $2.25 billion resulting from an event of a non-nuclear origin. In addition, a builder's risk insurance policy has been purchased from NEIL for the construction of the New Units. This policy provides the owners of the New Units up to $500 million of total coverage for accidental property damage occurring during construction. The NEIL policies, in the aggregate, are subject to a maximum loss of $2.75 billion for any single loss occurrence. All of the NEIL policies permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $43.5 million. SCE&G currently maintains an excess property insurance policy (for itself and on behalf of Santee Cooper) with EMANI. The policy provides coverage to Summer Station Unit 1 for property damage and outage costs up to $415 million resulting from an event of a non-nuclear origin. The EMANI policy permits retrospective assessments under certain conditions to cover insurer's losses. Based on the current annual premium, SCE&G's portion of the retrospective premium assessment would not exceed $1.8 million.

To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from an incident at 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 or other incident. However, if such an incident were to occur, it likely would have a material impact on the Company’s and Consolidated SCE&G's results of operations, cash flows and financial position.

New Nuclear Construction

In 2008, SCE&G, on behalf of itself and as agent for Santee Cooper, contracted with the Consortium for the design and construction of the New Units at the site of Summer Station. SCE&G's current ownership share in the New Units is 55%. As discussed below, SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper.

EPC Contract and BLRA Matters

The construction of the New Units and SCE&G’s related recovery of financing costs through rates is subject to review and approval by the SCPSC as provided for in the BLRA. Under the BLRA, the SCPSC has approved, among other things, a milestone schedule and a capital costs estimates schedule for the New Units. This approval constitutes a final and binding determination that the New Units are used and useful for utility purposes, and that the capital costs associated with the New Units are prudent utility costs and expenses and are properly included in rates, so long as the New Units are constructed or are being constructed within the parameters of the approved milestone schedule, including specified contingencies, and the approved capital costs estimates schedule. Subject to the same conditions, the BLRA provides that SCE&G may apply to the SCPSC annually for an order to recover through revised rates SCE&G’s weighted average cost of capital applied to all or part of the outstanding balance of construction work in progress concerning the New Units. As of March 31, 2016, SCE&G’s investment in the New Units, including related transmission, totaled $3.8 billion, for which the financing costs on $3.2 billion have been reflected in rates under the BLRA.

The SCPSC granted initial approval of the construction schedule and related forecasted capital costs in 2009. The NRC issued COLs in March 2012. In November 2012, the SCPSC approved an updated milestone schedule and additional updated capital costs for the New Units. In addition, the SCPSC approved revised substantial completion dates for the New Units based on that March 2012 issuance of the COL and the amounts agreed upon by SCE&G and the Consortium in July 2012 to resolve known claims by the Consortium for costs related to COL delays, design modifications of the shield building and certain prefabricated structural modules for the New Units and unanticipated rock conditions at the site. In October 2014, the South Carolina Supreme Court affirmed the SCPSC's order on appeal.

Since the settlement of delay-related claims in 2012, the Consortium has continued to experience delays in the schedule. Shield building construction remains a principal focus area for SCE&G’s oversight of the project. The primary critical path for both Unit 2 and Unit 3 runs through the fabrication of shield building components and the completion of shield building construction. For Unit 3, the critical path also runs through the setting of Containment Vessel Ring 1 and placement of concrete in certain areas of the nuclear island to form a foundation for the shield building. Plans to accelerate the work needed to permit placing this concrete are underway. In addition, WEC has reached agreement on a mitigation plan to accelerate shield building panel fabrication with one of its subcontractors. Additional mitigation will be required in critical path areas to support the updated substantial completion dates described below.

During the fourth quarter of 2013, the Consortium began a full re-baselining of the Unit 2 and Unit 3 construction schedules to incorporate a more detailed evaluation of the engineering and procurement activities necessary to accomplish the schedules and to provide a detailed reassessment of the impact of the revised Unit 2 and Unit 3 schedules on engineering and design resource allocations, procurement, construction work crew efficiencies and other items. The result was a revised fully integrated project schedule with timing of specific construction activities (Revised, Fully-Integrated Construction Schedule) along with related cost information.

The Revised, Fully-Integrated Construction Schedule indicated that the substantial completion of Unit 2 was expected to occur in June 2019 and that the substantial completion of Unit 3 was expected to be approximately 12 months later. The Consortium continues to refine and update the Revised, Fully-Integrated Construction Schedule as designs are finalized, as construction progresses, and as additional information is received.

In September 2015, the SCPSC approved an updated BLRA milestone schedule based on revised substantial completion dates for Units 2 and 3 of June 2019 and June 2020, respectively, each subject to an 18-month contingency period. In addition, the SCPSC approved certain updated owner's costs ($245 million) and other capital costs ($453 million), of which $539 million were associated with the schedule delays and other contested costs. In this proceeding, SCE&G's total projected capital costs (in 2007 dollars) and gross construction cost estimates (including escalation and AFC) were estimated to be $5.2 billion and $6.8 billion, respectively. These projections included cost amounts related to the Revised, Fully-Integrated Construction Schedule for which SCE&G had not accepted responsibility and which were the subject of dispute. As such, the updated milestone schedule and projections did not reflect the resolution of negotiations. In addition, the SCPSC approved a revision to the allowed return on equity for new nuclear construction from 11.0% to 10.5%. This revised return on equity will be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2016, until such time as the New Units are completed.

On October 27, 2015, SCE&G, Santee Cooper and the Consortium reached a settlement regarding the above mentioned disputes, and the EPC Contract was amended. The October 2015 Amendment became effective in December 2015, upon the consummation of the acquisition by WEC of the stock of Stone & Webster from CB&I. Following that acquisition, Stone & Webster continues to be a member of the Consortium as a subsidiary of WEC rather than CB&I, and WEC has engaged Fluor Corporation as a subcontracted construction manager.

Among other things, the October 2015 Amendment:

(i) resolved by settlement and release most outstanding disputes between SCE&G and the Consortium, in exchange for (a) an additional cost to be paid by SCE&G and Santee Cooper of $300 million (SCE&G’s 55% portion being $165 million and an increase in the fixed component of the contract price by that amount, and (b) a credit to SCE&G and Santee Cooper of $50 million (SCE&G’s 55% portion being approximately $27 million) to be applied to the target component of the contract price,

(ii) revised the guaranteed substantial completion dates of Units 2 and 3 to August 31, 2019 and 2020, respectively,

(iii) revised the delay-related liquidated damages computation requirements, including those related to the eligibility of the New Units to earn Internal Revenue Code Section 45J production tax credits (see also below), and capped those aggregate liquidated damages at $463 million per New Unit (SCE&G’s 55% portion being approximately $255 million per New Unit),

(iv) provides for payment to the Consortium of a completion bonus of $275 million per New Unit (SCE&G’s 55% portion being approximately $151 million per New Unit) for each New Unit placed in service by the deadline to qualify for production tax credits,

(v) provides for development of a revised construction milestone payment schedule, with SCE&G and Santee Cooper making monthly payments of $100 million (SCE&G’s 55% portion being $55 million) for each of the first five months following effectiveness, followed by payments made based on milestones achieved, and

(vi) provided that SCE&G and Santee Cooper waive and cancel the CB&I parent company guaranty with respect to the project.

Under the October 2015 Amendment, SCE&G’s total estimated project costs increased by approximately $286 million over the $6.8 billion approved by the SCPSC in September 2015. In addition, SCE&G has updated project costs for estimated change orders related to certain outstanding disputes not resolved by the October 2015 Amendment. As of April 30, 2016, these estimated change orders total approximately $53 million. The estimated gross construction cost of the project (including the effects of these change orders, escalation and AFC) as of March 31, 2016 totals approximately $7.2 billion.

As of March 31, 2016, payments related to (i) above had been made totaling $62.5 million (SCE&G's 55% portion being approximately $34.4 million), and payments related to (v) above had been made totaling $300 million (SCE&G's 55% portion being $165 million).

Payment and performance obligations under the EPC Contract are joint and several obligations of WEC and Stone & Webster, and in connection with the October 2015 Amendment, Toshiba Corporation, WEC’s parent company, reaffirmed its guaranty of WEC’s payment obligations. Additionally, the EPC Contract provides the Owners the right, exercisable upon certain conditions, to obtain payment and performance bonds from WEC equal to 15%of the highest three months billings during the applicable year, and their aggregate nominal coverage will not exceed $100 million (or $55 millionfor SCE&G's 55% share). SCE&G and Santee Cooper are responsible for the cost of the bonds.

In late 2015, Toshiba's credit ratings declined to below investment grade following disclosures regarding its operating and financial performance and near-term liquidity. As a result, pursuant to the above-described terms of the EPC Contract, SCE&G has obtained payment and performance bonds from WEC in the form of standby letters of credit totaling $45 million(or approximately $25 millionfor SCE&G's 55% share). These standby letters of credit expire annually and automatically renew for successive one-year periods until their final expiration date of August 31, 2020, unless the issuer provides a minimum 60-day notice that it will not renew. In the event that WEC would be unable to meet its payment and performance obligations under the EPC Contract, it is anticipated this funding would provide a source of liquidity to assist in an orderly transition and in enabling construction activities to continue. In addition, the EPC Contract provides that upon the request of SCE&G, the Consortium must escrow certain intellectual property and software for SCE&G's benefit to enable completion of the New Units. An escrow arrangement and a schedule for deposit of intellectual property and software are being developed. While there have been no indications to date that WEC will not meet its obligations under the EPC Contract, SCE&G cannot predict the outcome of these matters, and continues to monitor developments for potential impacts to both the construction schedule and costs.

In addition to the above, the October 2015 Amendment provided for an explicit definition of a Change in Law designed to reduce the likelihood of certain future commercial disputes, and the Consortium also acknowledged and agreed that the project scope includes providing New Units that meet the standards of the NRC approved Design Control Document Revision 19. The October 2015 Amendment also established a dispute resolution board process for certain commercial claims and disputes, including any dispute that might arise with respect to the development of the revised construction milestone payment schedule referred to above. The EPC Contract was also revised to eliminate the requirement or ability to bring suit before substantial completion of the project.

Finally, the October 2015 Amendment provides SCE&G and Santee Cooper an irrevocable option, until November 1, 2016 and subject to regulatory approvals, to further amend the EPC Contract to fix the total amount to be paid to the Consortium for its entire scope of work on the project (excluding a limited amount of work within the time and materials component of the contract price) after June 30, 2015 at $6.082 billion (SCE&G’s 55% portion being approximately $3.345 billion). This total amount to be paid would be subject to adjustment for amounts paid since June 30, 2015. Were this fixed price option to be exercised, the aggregate delay-related liquidated damages referred to in (iii) above would be capped at $338 million per unit (SCE&G’s 55% portion being approximately $186 million per unit), and the completion bonus referred to in (iv) above would be $150 million per New Unit (SCE&G’s 55% portion being approximately $83 million per New Unit). The exercise of this fixed price option would result in SCE&G’s total estimated project costs increasing by approximately $774 million over the $6.8 billion approved by the SCPSC in September 2015. This increase does not include the estimated change orders described previously totaling approximately $53 million and additional sales tax that would be due under this fixed price option of approximately $10 million. The estimated gross construction cost of the project (including the effects of these change orders and additional sales tax, escalation and AFC) under this fixed price option would total approximately $7.7 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 in September 2015; however, the guaranteed substantial completion dates fall within the SCPSC approved 18-month contingency periods. SCE&G held an allowable ex parte communication briefing with the SCPSC on November 19, 2015 and, following an evaluation as to whether to exercise the fixed price option, expects to file a petition in the second quarter of 2016, as provided under the BLRA, for an update to the project’s estimated capital cost and milestone schedule which incorporates the impact of the October 2015 Amendment. Such update would also incorporate any cost or schedule changes identified since that time.

Additional claims by the Consortium or SCE&G involving the project schedule and budget may arise as the project continues. The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve such issues. SCE&G expects to resolve all disputes through both the informal and formal procedures and currently anticipates that any costs that arise through such dispute resolution processes (including those reflected in the October 2015 Amendment described above), as well as other costs identified from time to time, will be recoverable through rates.

Santee Cooper Matters

As noted above, SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper. Under the terms of this agreement, SCE&G will acquire a 1% ownership interest in the New Units at the commercial operation date of Unit 2, an additional 2% ownership interest no later than the first anniversary of such commercial operation date, and the final 2% no later than the second anniversary of such commercial operation date. SCE&G has agreed to pay an amount equal to Santee Cooper's actual cost, including its cost of financing, of the percentage conveyed as of the date of each conveyance. In addition, the agreement provides that Santee Cooper will not transfer any of its remaining interest in the New Units to third parties until the New Units are complete. This transaction will not affect the payment obligations between the parties during construction for the New Units, nor is it anticipated that the payments for the additional ownership interest would be reflected in a revised rates filing under the BLRA. Based on the October 2015 Amendment, which has not been approved by the SCPSC, SCE&G’s currently projected cost would be approximately $750 million to $850 million for the additional 5% interest being acquired from Santee Cooper.

Nuclear Production Tax Credits

The IRS has notified SCE&G that, subject to a national megawatt capacity limitation, the electricity to be produced by each of the New Units (advanced nuclear units, as defined) would qualify for nuclear production tax credits under Section 45J of the Internal Revenue Code to the extent that such New Unit is operational before January 1, 2021 and other eligibility requirements are met. These nuclear production tax credits (related to SCE&G's 55% share of both New Units) could total as much as approximately $1.4 billion. Such credits would be earned over the first eight years of each New Unit's operations and would be realized by SCE&G over those years or during allowable carry-forward periods. Based on the guaranteed substantial completion dates provided above, both New Units are expected to be operational and to qualify for the nuclear production tax credits; however, further delays in the schedule or changes in tax law could impact such conclusions. When and to the extent that production tax credits are realized, their benefits are expected to be provided directly to SCE&G's electric customers.

Other Project Matters

When the NRC issued the COLs for the New Units, two of the conditions that it imposed were requiring inspection and testing of certain components of the New Units' passive cooling system, and requiring the development of strategies to respond to extreme natural events resulting in the loss of power at the New Units. In addition, the NRC directed the Office of New Reactors to issue to SCE&G an order requiring enhanced, reliable spent fuel pool instrumentation. SCE&G prepared and submitted an overall integration plan for the New Units to the NRC in August 2013. That plan is currently under review by the NRC and SCE&G does not anticipate any additional regulatory actions as a result of that review, but it cannot predict future regulatory activities or how such initiatives would impact construction or operation of the New Units.

Environmental

On August 3, 2015, the EPA issued its final rule on emission guidelines for states to follow in developing plans to address GHG emissions from existing units. The rule includes state-specific goals for reducing national carbon dioxide emissions by 32% from 2005 levels by 2030. The rule also provides for nuclear reactors under construction, such as the New Units, to count towards compliance and establishes a phased-in compliance approach beginning in 2022. The rule gives states from one to three years to issue SIPs, which will ultimately define the specific compliance methodology that will be applied to existing units in that state. On February 9, 2016, the Supreme Court stayed the rule pending disposition of a petition of review of the rule in the Court of Appeals. The order of the Supreme Court has no immediate impact on SCE&G and GENCO or their generation operations. The Company and Consolidated SCE&G are currently evaluating the rule and expect any costs incurred to comply with such rule to be recoverable through rates.

In July 2011, the EPA issued the CSAPR to reduce emissions of sulfur dioxide and nitrogen oxide from power plants in the eastern half of the United States. A series of court actions stayed this rule until October 23, 2014, when the Court of Appeals granted a motion to lift the stay. On December 3, 2014, the EPA published an interim final rule that aligns the dates in the CSAPR text with the revised court-ordered schedule, which delayed the implementation dates to 2015 for Phase 1 and to 2017 for Phase 2. The CSAPR replaces the CAIR and requires a total of 28 states to reduce annual sulfur dioxide emissions and annual and 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 costs incurred to comply with CSAPR are expected to be recoverable through rates.

In April 2012, the EPA's MATS rule containing new standards for mercury and other specified air pollutants became effective. The Company's and Consolidated SCE&G's decision to retire certain coal-fired units and its project to build the New Units along with other actions are expected to result in the Company's and Consolidated SCE&G's compliance with MATS.

On November 19, 2014, the EPA finalized its reconsideration of certain provisions applicable during startup and shutdown of generating facilities under the MATS rule. SCE&G and GENCO were granted a one year extension (through April 2016) to comply with MATS at Cope, McMeekin, Wateree and Williams Stations. These extensions allowed time to convert McMeekin Station to burn natural gas and to install additional pollution control devices at the other plants to enhance the control of certain MATS-regulated pollutants. On June 29, 2015, the Supreme Court ruled that the EPA unreasonably failed to consider costs in its decision to regulate. In December 2015, the Court of Appeals ruled that the MATS rule would remain in effect while the EPA assesses the cost of the rule. These rulings are not expected to have an impact on SCE&G or GENCO due to the aforementioned retirements and conversions. SCE&G and GENCO currently are in compliance with the MATS rule and expect to remain in compliance.

The CWA provides for the imposition of effluent limitations that require treatment for wastewater discharges. Under the CWA, compliance with applicable limitations is achieved under state-issued NPDES permits. As a facility’s NPDES permit is renewed (every five years), any new effluent limitations would be incorporated. The ELG Rule became effective on January 4, 2016. After this date, state regulators will modify facility NPDES permits to match more restrictive standards, thus requiring facilities to retrofit with new wastewater treatment technologies. Compliance dates will vary by type of wastewater, and some will be based on a facility's five year permit cycle and thus may range from 2018 to 2023. The Company and Consolidated SCE&G expect 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 as required by the rule to determine appropriate intake structure modifications to ensure compliance with this rule. Any costs incurred to comply with this rule are expected to be recoverable through rates. 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.

The EPA's final rule for CCR became effective in the fourth quarter of 2015. This rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act and imposes certain requirements on ash storage ponds and other CCR management facilities at SCE&G's and GENCO's coal-fired generating facilities. SCE&G and GENCO have already closed or have begun the process of closure of all of their ash storage ponds and have previously recognized AROs for such ash storage ponds under existing requirements. The Company and Consolidated SCE&G do not expect the incremental compliance costs associated with this rule to be significant and expect to recover such costs in future rates.

The Nuclear Waste Act required that the United States government accept and permanently dispose of high-level radioactive waste and spent nuclear fuel by January 31, 1998, and it imposed on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. SCE&G entered into a Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with the DOE in 1983. As of December 31, 2015, the federal government has not accepted any spent fuel from Summer Station Unit 1, and it remains unclear when the repository may become available. SCE&G has on-site spent nuclear fuel storage capability in its existing fuel pool until at least 2017 and has constructed an independent spent fuel storage installation 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.

SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC and the EPA. SCE&G anticipates that major remediation activities at all these sites will continue at least through 2017 and will cost an additional $18.4 million, which is accrued in Other within Deferred Credits and Other Liabilities on the consolidated balance sheet. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates. At March 31, 2016, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $34.4 million and are included in regulatory assets.

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 $13.4 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $375 million by ANI with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. Each reactor licensee is currently liable for up to $127.3 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $18.9 million of the liability per reactor would be assessed per year. SCE&G’s maximum assessment, based on its two-thirds ownership of Summer Station Unit 1, would be $84.8 million per incident, but not more than $12.6 million per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years.

SCE&G currently maintains insurance policies (for itself and on behalf of Santee Cooper) with NEIL. The policies provide coverage to Summer Station Unit 1 for property damage and outage costs up to $2.75 billion resulting from an event of nuclear origin and up to $2.25 billion resulting from an event of a non-nuclear origin. In addition, a builder's risk insurance policy has been purchased from NEIL for the construction of the New Units. This policy provides the owners of the New Units up to $500 million of total coverage for accidental property damage occurring during construction. The NEIL policies, in the aggregate, are subject to a maximum loss of $2.75 billion for any single loss occurrence. All of the NEIL policies permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $43.5 million. SCE&G currently maintains an excess property insurance policy (for itself and on behalf of Santee Cooper) with EMANI. The policy provides coverage to Summer Station Unit 1 for property damage and outage costs up to $415 million resulting from an event of a non-nuclear origin. The EMANI policy permits retrospective assessments under certain conditions to cover insurer's losses. Based on the current annual premium, SCE&G's portion of the retrospective premium assessment would not exceed $1.8 million.

To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from an incident at 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 or other incident. However, if such an incident were to occur, it likely would have a material impact on the Company’s and Consolidated SCE&G's results of operations, cash flows and financial position.

New Nuclear Construction

In 2008, SCE&G, on behalf of itself and as agent for Santee Cooper, contracted with the Consortium for the design and construction of the New Units at the site of Summer Station. SCE&G's current ownership share in the New Units is 55%. As discussed below, SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper.

EPC Contract and BLRA Matters

The construction of the New Units and SCE&G’s related recovery of financing costs through rates is subject to review and approval by the SCPSC as provided for in the BLRA. Under the BLRA, the SCPSC has approved, among other things, a milestone schedule and a capital costs estimates schedule for the New Units. This approval constitutes a final and binding determination that the New Units are used and useful for utility purposes, and that the capital costs associated with the New Units are prudent utility costs and expenses and are properly included in rates, so long as the New Units are constructed or are being constructed within the parameters of the approved milestone schedule, including specified contingencies, and the approved capital costs estimates schedule. Subject to the same conditions, the BLRA provides that SCE&G may apply to the SCPSC annually for an order to recover through revised rates SCE&G’s weighted average cost of capital applied to all or part of the outstanding balance of construction work in progress concerning the New Units. As of March 31, 2016, SCE&G’s investment in the New Units, including related transmission, totaled $3.8 billion, for which the financing costs on $3.2 billion have been reflected in rates under the BLRA.

The SCPSC granted initial approval of the construction schedule and related forecasted capital costs in 2009. The NRC issued COLs in March 2012. In November 2012, the SCPSC approved an updated milestone schedule and additional updated capital costs for the New Units. In addition, the SCPSC approved revised substantial completion dates for the New Units based on that March 2012 issuance of the COL and the amounts agreed upon by SCE&G and the Consortium in July 2012 to resolve known claims by the Consortium for costs related to COL delays, design modifications of the shield building and certain prefabricated structural modules for the New Units and unanticipated rock conditions at the site. In October 2014, the South Carolina Supreme Court affirmed the SCPSC's order on appeal.

Since the settlement of delay-related claims in 2012, the Consortium has continued to experience delays in the schedule. Shield building construction remains a principal focus area for SCE&G’s oversight of the project. The primary critical path for both Unit 2 and Unit 3 runs through the fabrication of shield building components and the completion of shield building construction. For Unit 3, the critical path also runs through the setting of Containment Vessel Ring 1 and placement of concrete in certain areas of the nuclear island to form a foundation for the shield building. Plans to accelerate the work needed to permit placing this concrete are underway. In addition, WEC has reached agreement on a mitigation plan to accelerate shield building panel fabrication with one of its subcontractors. Additional mitigation will be required in critical path areas to support the updated substantial completion dates described below.

During the fourth quarter of 2013, the Consortium began a full re-baselining of the Unit 2 and Unit 3 construction schedules to incorporate a more detailed evaluation of the engineering and procurement activities necessary to accomplish the schedules and to provide a detailed reassessment of the impact of the revised Unit 2 and Unit 3 schedules on engineering and design resource allocations, procurement, construction work crew efficiencies and other items. The result was a revised fully integrated project schedule with timing of specific construction activities (Revised, Fully-Integrated Construction Schedule) along with related cost information.

The Revised, Fully-Integrated Construction Schedule indicated that the substantial completion of Unit 2 was expected to occur in June 2019 and that the substantial completion of Unit 3 was expected to be approximately 12 months later. The Consortium continues to refine and update the Revised, Fully-Integrated Construction Schedule as designs are finalized, as construction progresses, and as additional information is received.

In September 2015, the SCPSC approved an updated BLRA milestone schedule based on revised substantial completion dates for Units 2 and 3 of June 2019 and June 2020, respectively, each subject to an 18-month contingency period. In addition, the SCPSC approved certain updated owner's costs ($245 million) and other capital costs ($453 million), of which $539 million were associated with the schedule delays and other contested costs. In this proceeding, SCE&G's total projected capital costs (in 2007 dollars) and gross construction cost estimates (including escalation and AFC) were estimated to be $5.2 billion and $6.8 billion, respectively. These projections included cost amounts related to the Revised, Fully-Integrated Construction Schedule for which SCE&G had not accepted responsibility and which were the subject of dispute. As such, the updated milestone schedule and projections did not reflect the resolution of negotiations. In addition, the SCPSC approved a revision to the allowed return on equity for new nuclear construction from 11.0% to 10.5%. This revised return on equity will be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2016, until such time as the New Units are completed.

On October 27, 2015, SCE&G, Santee Cooper and the Consortium reached a settlement regarding the above mentioned disputes, and the EPC Contract was amended. The October 2015 Amendment became effective in December 2015, upon the consummation of the acquisition by WEC of the stock of Stone & Webster from CB&I. Following that acquisition, Stone & Webster continues to be a member of the Consortium as a subsidiary of WEC rather than CB&I, and WEC has engaged Fluor Corporation as a subcontracted construction manager.

Among other things, the October 2015 Amendment:

(i) resolved by settlement and release most outstanding disputes between SCE&G and the Consortium, in exchange for (a) an additional cost to be paid by SCE&G and Santee Cooper of $300 million (SCE&G’s 55% portion being $165 million and an increase in the fixed component of the contract price by that amount, and (b) a credit to SCE&G and Santee Cooper of $50 million (SCE&G’s 55% portion being approximately $27 million) to be applied to the target component of the contract price,

(ii) revised the guaranteed substantial completion dates of Units 2 and 3 to August 31, 2019 and 2020, respectively,

(iii) revised the delay-related liquidated damages computation requirements, including those related to the eligibility of the New Units to earn Internal Revenue Code Section 45J production tax credits (see also below), and capped those aggregate liquidated damages at $463 million per New Unit (SCE&G’s 55% portion being approximately $255 million per New Unit),

(iv) provides for payment to the Consortium of a completion bonus of $275 million per New Unit (SCE&G’s 55% portion being approximately $151 million per New Unit) for each New Unit placed in service by the deadline to qualify for production tax credits,

(v) provides for development of a revised construction milestone payment schedule, with SCE&G and Santee Cooper making monthly payments of $100 million (SCE&G’s 55% portion being $55 million) for each of the first five months following effectiveness, followed by payments made based on milestones achieved, and

(vi) provided that SCE&G and Santee Cooper waive and cancel the CB&I parent company guaranty with respect to the project.

Under the October 2015 Amendment, SCE&G’s total estimated project costs increased by approximately $286 million over the $6.8 billion approved by the SCPSC in September 2015. In addition, SCE&G has updated project costs for estimated change orders related to certain outstanding disputes not resolved by the October 2015 Amendment. As of April 30, 2016, these estimated change orders total approximately $53 million. The estimated gross construction cost of the project (including the effects of these change orders, escalation and AFC) as of March 31, 2016 totals approximately $7.2 billion.

As of March 31, 2016, payments related to (i) above had been made totaling $62.5 million (SCE&G's 55% portion being approximately $34.4 million), and payments related to (v) above had been made totaling $300 million (SCE&G's 55% portion being $165 million).

Payment and performance obligations under the EPC Contract are joint and several obligations of WEC and Stone & Webster, and in connection with the October 2015 Amendment, Toshiba Corporation, WEC’s parent company, reaffirmed its guaranty of WEC’s payment obligations. Additionally, the EPC Contract provides the Owners the right, exercisable upon certain conditions, to obtain payment and performance bonds from WEC equal to 15%of the highest three months billings during the applicable year, and their aggregate nominal coverage will not exceed $100 million (or $55 millionfor SCE&G's 55% share). SCE&G and Santee Cooper are responsible for the cost of the bonds.

In late 2015, Toshiba's credit ratings declined to below investment grade following disclosures regarding its operating and financial performance and near-term liquidity. As a result, pursuant to the above-described terms of the EPC Contract, SCE&G has obtained payment and performance bonds from WEC in the form of standby letters of credit totaling $45 million(or approximately $25 millionfor SCE&G's 55% share). These standby letters of credit expire annually and automatically renew for successive one-year periods until their final expiration date of August 31, 2020, unless the issuer provides a minimum 60-day notice that it will not renew. In the event that WEC would be unable to meet its payment and performance obligations under the EPC Contract, it is anticipated this funding would provide a source of liquidity to assist in an orderly transition and in enabling construction activities to continue. In addition, the EPC Contract provides that upon the request of SCE&G, the Consortium must escrow certain intellectual property and software for SCE&G's benefit to enable completion of the New Units. An escrow arrangement and a schedule for deposit of intellectual property and software are being developed. While there have been no indications to date that WEC will not meet its obligations under the EPC Contract, SCE&G cannot predict the outcome of these matters, and continues to monitor developments for potential impacts to both the construction schedule and costs.

In addition to the above, the October 2015 Amendment provided for an explicit definition of a Change in Law designed to reduce the likelihood of certain future commercial disputes, and the Consortium also acknowledged and agreed that the project scope includes providing New Units that meet the standards of the NRC approved Design Control Document Revision 19. The October 2015 Amendment also established a dispute resolution board process for certain commercial claims and disputes, including any dispute that might arise with respect to the development of the revised construction milestone payment schedule referred to above. The EPC Contract was also revised to eliminate the requirement or ability to bring suit before substantial completion of the project.

Finally, the October 2015 Amendment provides SCE&G and Santee Cooper an irrevocable option, until November 1, 2016 and subject to regulatory approvals, to further amend the EPC Contract to fix the total amount to be paid to the Consortium for its entire scope of work on the project (excluding a limited amount of work within the time and materials component of the contract price) after June 30, 2015 at $6.082 billion (SCE&G’s 55% portion being approximately $3.345 billion). This total amount to be paid would be subject to adjustment for amounts paid since June 30, 2015. Were this fixed price option to be exercised, the aggregate delay-related liquidated damages referred to in (iii) above would be capped at $338 million per unit (SCE&G’s 55% portion being approximately $186 million per unit), and the completion bonus referred to in (iv) above would be $150 million per New Unit (SCE&G’s 55% portion being approximately $83 million per New Unit). The exercise of this fixed price option would result in SCE&G’s total estimated project costs increasing by approximately $774 million over the $6.8 billion approved by the SCPSC in September 2015. This increase does not include the estimated change orders described previously totaling approximately $53 million and additional sales tax that would be due under this fixed price option of approximately $10 million. The estimated gross construction cost of the project (including the effects of these change orders and additional sales tax, escalation and AFC) under this fixed price option would total approximately $7.7 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 in September 2015; however, the guaranteed substantial completion dates fall within the SCPSC approved 18-month contingency periods. SCE&G held an allowable ex parte communication briefing with the SCPSC on November 19, 2015 and, following an evaluation as to whether to exercise the fixed price option, expects to file a petition in the second quarter of 2016, as provided under the BLRA, for an update to the project’s estimated capital cost and milestone schedule which incorporates the impact of the October 2015 Amendment. Such update would also incorporate any cost or schedule changes identified since that time.

Additional claims by the Consortium or SCE&G involving the project schedule and budget may arise as the project continues. The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve such issues. SCE&G expects to resolve all disputes through both the informal and formal procedures and currently anticipates that any costs that arise through such dispute resolution processes (including those reflected in the October 2015 Amendment described above), as well as other costs identified from time to time, will be recoverable through rates.

Santee Cooper Matters

As noted above, SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper. Under the terms of this agreement, SCE&G will acquire a 1% ownership interest in the New Units at the commercial operation date of Unit 2, an additional 2% ownership interest no later than the first anniversary of such commercial operation date, and the final 2% no later than the second anniversary of such commercial operation date. SCE&G has agreed to pay an amount equal to Santee Cooper's actual cost, including its cost of financing, of the percentage conveyed as of the date of each conveyance. In addition, the agreement provides that Santee Cooper will not transfer any of its remaining interest in the New Units to third parties until the New Units are complete. This transaction will not affect the payment obligations between the parties during construction for the New Units, nor is it anticipated that the payments for the additional ownership interest would be reflected in a revised rates filing under the BLRA. Based on the October 2015 Amendment, which has not been approved by the SCPSC, SCE&G’s currently projected cost would be approximately $750 million to $850 million for the additional 5% interest being acquired from Santee Cooper.

Nuclear Production Tax Credits

The IRS has notified SCE&G that, subject to a national megawatt capacity limitation, the electricity to be produced by each of the New Units (advanced nuclear units, as defined) would qualify for nuclear production tax credits under Section 45J of the Internal Revenue Code to the extent that such New Unit is operational before January 1, 2021 and other eligibility requirements are met. These nuclear production tax credits (related to SCE&G's 55% share of both New Units) could total as much as approximately $1.4 billion. Such credits would be earned over the first eight years of each New Unit's operations and would be realized by SCE&G over those years or during allowable carry-forward periods. Based on the guaranteed substantial completion dates provided above, both New Units are expected to be operational and to qualify for the nuclear production tax credits; however, further delays in the schedule or changes in tax law could impact such conclusions. When and to the extent that production tax credits are realized, their benefits are expected to be provided directly to SCE&G's electric customers.

Other Project Matters

When the NRC issued the COLs for the New Units, two of the conditions that it imposed were requiring inspection and testing of certain components of the New Units' passive cooling system, and requiring the development of strategies to respond to extreme natural events resulting in the loss of power at the New Units. In addition, the NRC directed the Office of New Reactors to issue to SCE&G an order requiring enhanced, reliable spent fuel pool instrumentation. SCE&G prepared and submitted an overall integration plan for the New Units to the NRC in August 2013. That plan is currently under review by the NRC and SCE&G does not anticipate any additional regulatory actions as a result of that review, but it cannot predict future regulatory activities or how such initiatives would impact construction or operation of the New Units.

Environmental

On August 3, 2015, the EPA issued its final rule on emission guidelines for states to follow in developing plans to address GHG emissions from existing units. The rule includes state-specific goals for reducing national carbon dioxide emissions by 32% from 2005 levels by 2030. The rule also provides for nuclear reactors under construction, such as the New Units, to count towards compliance and establishes a phased-in compliance approach beginning in 2022. The rule gives states from one to three years to issue SIPs, which will ultimately define the specific compliance methodology that will be applied to existing units in that state. On February 9, 2016, the Supreme Court stayed the rule pending disposition of a petition of review of the rule in the Court of Appeals. The order of the Supreme Court has no immediate impact on SCE&G and GENCO or their generation operations. The Company and Consolidated SCE&G are currently evaluating the rule and expect any costs incurred to comply with such rule to be recoverable through rates.

In July 2011, the EPA issued the CSAPR to reduce emissions of sulfur dioxide and nitrogen oxide from power plants in the eastern half of the United States. A series of court actions stayed this rule until October 23, 2014, when the Court of Appeals granted a motion to lift the stay. On December 3, 2014, the EPA published an interim final rule that aligns the dates in the CSAPR text with the revised court-ordered schedule, which delayed the implementation dates to 2015 for Phase 1 and to 2017 for Phase 2. The CSAPR replaces the CAIR and requires a total of 28 states to reduce annual sulfur dioxide emissions and annual and 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 costs incurred to comply with CSAPR are expected to be recoverable through rates.

In April 2012, the EPA's MATS rule containing new standards for mercury and other specified air pollutants became effective. The Company's and Consolidated SCE&G's decision to retire certain coal-fired units and its project to build the New Units along with other actions are expected to result in the Company's and Consolidated SCE&G's compliance with MATS.

On November 19, 2014, the EPA finalized its reconsideration of certain provisions applicable during startup and shutdown of generating facilities under the MATS rule. SCE&G and GENCO were granted a one year extension (through April 2016) to comply with MATS at Cope, McMeekin, Wateree and Williams Stations. These extensions allowed time to convert McMeekin Station to burn natural gas and to install additional pollution control devices at the other plants to enhance the control of certain MATS-regulated pollutants. On June 29, 2015, the Supreme Court ruled that the EPA unreasonably failed to consider costs in its decision to regulate. In December 2015, the Court of Appeals ruled that the MATS rule would remain in effect while the EPA assesses the cost of the rule. These rulings are not expected to have an impact on SCE&G or GENCO due to the aforementioned retirements and conversions. SCE&G and GENCO currently are in compliance with the MATS rule and expect to remain in compliance.

The CWA provides for the imposition of effluent limitations that require treatment for wastewater discharges. Under the CWA, compliance with applicable limitations is achieved under state-issued NPDES permits. As a facility’s NPDES permit is renewed (every five years), any new effluent limitations would be incorporated. The ELG Rule became effective on January 4, 2016. After this date, state regulators will modify facility NPDES permits to match more restrictive standards, thus requiring facilities to retrofit with new wastewater treatment technologies. Compliance dates will vary by type of wastewater, and some will be based on a facility's five year permit cycle and thus may range from 2018 to 2023. The Company and Consolidated SCE&G expect 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 as required by the rule to determine appropriate intake structure modifications to ensure compliance with this rule. Any costs incurred to comply with this rule are expected to be recoverable through rates. 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.

The EPA's final rule for CCR became effective in the fourth quarter of 2015. This rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act and imposes certain requirements on ash storage ponds and other CCR management facilities at SCE&G's and GENCO's coal-fired generating facilities. SCE&G and GENCO have already closed or have begun the process of closure of all of their ash storage ponds and have previously recognized AROs for such ash storage ponds under existing requirements. The Company and Consolidated SCE&G do not expect the incremental compliance costs associated with this rule to be significant and expect to recover such costs in future rates.

The Nuclear Waste Act required that the United States government accept and permanently dispose of high-level radioactive waste and spent nuclear fuel by January 31, 1998, and it imposed on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. SCE&G entered into a Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with the DOE in 1983. As of December 31, 2015, the federal government has not accepted any spent fuel from Summer Station Unit 1, and it remains unclear when the repository may become available. SCE&G has on-site spent nuclear fuel storage capability in its existing fuel pool until at least 2017 and has constructed an independent spent fuel storage installation 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.

SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC and the EPA. SCE&G anticipates that major remediation activities at all these sites will continue at least through 2017 and will cost an additional $18.4 million, which is accrued in Other within Deferred Credits and Other Liabilities on the consolidated balance sheet. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates. At March 31, 2016, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $34.4 million and are included in regulatory assets.

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SEGMENT OF BUSINESS INFORMATION

3 Months Ended

Mar. 31, 2016

Segment Reporting Information [Line Items]

Segment Reporting Disclosure [Text Block]

SEGMENT OF BUSINESS INFORMATION

Regulated operations measure profitability using operating income; therefore, net income is not allocated to the Electric Operations and Gas Distribution segments. Marketing segments measure profitability using net income.

The Company's Gas Distribution segment is comprised of the local distribution operations of SCE&G and PSNC Energy which meet the criteria for aggregation. All Other includes the parent company, a services company and other nonreportable segments that were insignificant for all periods presented. In addition, All Other includes gains from the sales of CGT and SCI (see Dispositions in Note 1) and their operating results and assets prior to their sale in the first quarter of 2015. CGT and SCI were nonreportable segments during all periods presented. For the period ended March 31, 2015, operating income and net income for All Other include $235 million million and $202 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 either period presented.

The Company
Millions of dollars	External Revenue		Intersegment Revenue			Operating Income		Net Income
Three Months Ended March 31, 2016
Electric Operations	$	592	$	1		$	198	n/a
Gas Distribution	299		1			94		n/a
Retail Gas Marketing	171		—			n/a		$	22
Energy Marketing	110		22			n/a		2
All Other	—		98			—		—
Adjustments/Eliminations	—		(122		)	39		152
Consolidated Total	$	1,172	$	—		$	331	$	176

Three Months Ended March 31, 2015
Electric Operations	$	629		—			$	199	n/a
Gas Distribution	368			—			96		n/a
Retail Gas Marketing	204			—			n/a		$	27
Energy Marketing	187			$	35		n/a		6
All Other	4			114			238		207
Adjustments/Eliminations	(3		)	(149		)	53		160
Consolidated Total	$	1,389		$	—		$	586	$	400

Consolidated SCE&G
Millions of dollars	External Revenue		Operating Income		Earnings Available to Common Shareholder
Three Months Ended March 31, 2016
Electric Operations	$	593	$	198	n/a
Gas Distributions	124		38		n/a
Adjustments/Eliminations	—		—		$	113
Consolidated Total	$	717	$	236	$	113

Three Months Ended March 31, 2015
Electric Operations	$	630	$	199	n/a
Gas Distributions	142		38		n/a
Adjustments/Eliminations	—		—		$	122
Consolidated Total	$	772	$	237	$	122

Segment Assets	The Company				Consolidated SCE&G
	March 31,		December 31,		March 31,		December 31,
Millions of dollars	2016		2015		2016		2015
Electric Operations	$	11,039	$	10,883	$	11,039	$	10,883
Gas Distribution	2,676		2,606		768		757
Retail Gas Marketing	140		106		n/a		n/a
Energy Marketing	84		95		n/a		n/a
All Other	994		998		n/a		n/a
Adjustments/Eliminations	2,435		2,458		3,125		3,125
Consolidated Total	$	17,368	$	17,146	$	14,932	$	14,765

SCEG

Segment Reporting Information [Line Items]

Segment Reporting Disclosure [Text Block]

SEGMENT OF BUSINESS INFORMATION

Regulated operations measure profitability using operating income; therefore, net income is not allocated to the Electric Operations and Gas Distribution segments. Marketing segments measure profitability using net income.

The Company's Gas Distribution segment is comprised of the local distribution operations of SCE&G and PSNC Energy which meet the criteria for aggregation. All Other includes the parent company, a services company and other nonreportable segments that were insignificant for all periods presented. In addition, All Other includes gains from the sales of CGT and SCI (see Dispositions in Note 1) and their operating results and assets prior to their sale in the first quarter of 2015. CGT and SCI were nonreportable segments during all periods presented. For the period ended March 31, 2015, operating income and net income for All Other include $235 million million and $202 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 either period presented.

The Company
Millions of dollars	External Revenue		Intersegment Revenue			Operating Income		Net Income
Three Months Ended March 31, 2016
Electric Operations	$	592	$	1		$	198	n/a
Gas Distribution	299		1			94		n/a
Retail Gas Marketing	171		—			n/a		$	22
Energy Marketing	110		22			n/a		2
All Other	—		98			—		—
Adjustments/Eliminations	—		(122		)	39		152
Consolidated Total	$	1,172	$	—		$	331	$	176

Three Months Ended March 31, 2015
Electric Operations	$	629		—			$	199	n/a
Gas Distribution	368			—			96		n/a
Retail Gas Marketing	204			—			n/a		$	27
Energy Marketing	187			$	35		n/a		6
All Other	4			114			238		207
Adjustments/Eliminations	(3		)	(149		)	53		160
Consolidated Total	$	1,389		$	—		$	586	$	400

Consolidated SCE&G
Millions of dollars	External Revenue		Operating Income		Earnings Available to Common Shareholder
Three Months Ended March 31, 2016
Electric Operations	$	593	$	198	n/a
Gas Distributions	124		38		n/a
Adjustments/Eliminations	—		—		$	113
Consolidated Total	$	717	$	236	$	113

Three Months Ended March 31, 2015
Electric Operations	$	630	$	199	n/a
Gas Distributions	142		38		n/a
Adjustments/Eliminations	—		—		$	122
Consolidated Total	$	772	$	237	$	122

Segment Assets	The Company				Consolidated SCE&G
	March 31,		December 31,		March 31,		December 31,
Millions of dollars	2016		2015		2016		2015
Electric Operations	$	11,039	$	10,883	$	11,039	$	10,883
Gas Distribution	2,676		2,606		768		757
Retail Gas Marketing	140		106		n/a		n/a
Energy Marketing	84		95		n/a		n/a
All Other	994		998		n/a		n/a
Adjustments/Eliminations	2,435		2,458		3,125		3,125
Consolidated Total	$	17,368	$	17,146	$	14,932	$	14,765

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AFFILIATED TRANSACTIONS - SCEG

3 Months Ended

Mar. 31, 2016

Related Party Transactions Disclosure [Text Block]

AFFILIATED TRANSACTIONS

The Company and Consolidated SCE&G:

SCE&G owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and sale of refined coal to reduce emissions. SCE&G accounts for this investment using the equity method.  SCE&G’s total purchases from this affiliate were $52.8 million and $70.1 million for the three months ended March 31, 2016 and 2015, respectively.  SCE&G’s total sales to this affiliate were $52.5 million and $69.7 million for the three months ended March 31, 2016 and 2015, respectively. SCE&G’s receivable from this affiliate was $15.2 million at March 31, 2016 and $12.8 million at December 31, 2015.  SCE&G’s payable to this affiliate was $15.3 million at March 31, 2016 and $12.9 million at December 31, 2015.

SCEG

Related Party Transactions Disclosure [Text Block]

AFFILIATED TRANSACTIONS

The Company and Consolidated SCE&G:

SCE&G owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and sale of refined coal to reduce emissions. SCE&G accounts for this investment using the equity method.  SCE&G’s total purchases from this affiliate were $52.8 million and $70.1 million for the three months ended March 31, 2016 and 2015, respectively.  SCE&G’s total sales to this affiliate were $52.5 million and $69.7 million for the three months ended March 31, 2016 and 2015, respectively. SCE&G’s receivable from this affiliate was $15.2 million at March 31, 2016 and $12.8 million at December 31, 2015.  SCE&G’s payable to this affiliate was $15.3 million at March 31, 2016 and $12.9 million at December 31, 2015.

Consolidated SCE&G:

Prior to January 31, 2015, CGT was a wholly-owned subsidiary of SCANA and transported natural gas to SCE&G to serve retail gas customers and certain electric generation requirements. SCE&G's purchases from CGT totaled approximately $3.4 million in January 2015.

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 $22.4 million and $34.6 million for the three months ended March 31, 2016 and 2015, respectively.  SCE&G’s payables to SEMI for such purchases were $4.0 million at March 31, 2016 and $7.5 million at December 31, 2015.

SCANA Services, Inc., on behalf of itself and its parent company, provides the following services to Consolidated SCE&G, which are rendered at direct or allocated cost: information systems 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 $75.6 million and $73.1 million for the three months ended March 31, 2016 and 2015, respectively. Consolidated SCE&G's payables to SCANA Services for these services were $48.1 million at March 31, 2016 and $57 million at December 31, 2015.

Consolidated SCE&G's money pool borrowings from an affiliate are described in Note 4.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

3 Months Ended

Mar. 31, 2016

Significant Accounting Policies

Earnings Per Share [Text Block]

Earnings Per Share

The Company computes basic earnings per share by dividing net income by the weighted average number of common shares outstanding for the period. The Company computes diluted earnings per share using this same formula, after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method. The weighted average number of common shares for each period presented for basic and diluted earnings per share purposes were identical.

Basis Of Consolidation And Variable Interest Entities [Policy Text Block]

Basis of Consolidation and Variable Interest Entities

The condensed consolidated financial statements of the Company include, after eliminating intercompany balances and transactions, the accounts of the parent holding company and each of its subsidiaries, including Consolidated SCE&G. Accordingly, discussions regarding the Company's financial results necessarily include the results of Consolidated SCE&G.

SCE&G has determined that it has a controlling financial interest in GENCO and Fuel Company (which are considered to be VIEs) and, accordingly, Consolidated SCE&G's condensed consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. As a result, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s condensed consolidated financial statements.

GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $488 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.

Dispositions [Policy Text Block]

Dispositions

In the first quarter of 2015, SCANA sold CGT and SCI. CGT was an interstate natural gas pipeline regulated by FERC that transported natural gas in South Carolina and southeastern Georgia, and it was sold to Dominion Resources, Inc. SCI provided fiber optic communications and other services and built, managed and leased communications towers in several southeastern states, and it was sold to a subsidiary of Spirit Communications. These sales resulted in recognition of pre-tax gains totaling approximately $342 million. As previously noted, the pre-tax gain from the sale of CGT is included within Operating Income and the pre-tax gain from the sale of SCI is included within Other Income (Expense) on the Company's condensed consolidated statement of income.

CGT and SCI operated principally in wholesale markets, whereas the Company's primary focus is the delivery of energy-related products and services to retail markets. In addition, neither CGT nor SCI met accounting criteria for disclosure as a reportable segment and were included within the All Other caption in Note 10. The sales of CGT and SCI did not represent a strategic shift that had a major effect on the Company's operations; therefore, these sales did not meet the criteria for classification as discontinued operations.

Asset Management and Supply Service Agreements

Asset Management and Supply Service Agreement

PSNC Energy, a subsidiary of SCANA, utilizes an asset management and supply service agreement with a counterparty for certain natural gas storage facilities.  Such counterparty held 29% and 46% of PSNC Energy’s natural gas inventory at March 31, 2016 and December 31, 2015, respectively, with a carrying value of $6.0 million and $17.7 million, respectively, through an agency relationship.  Under the terms of the asset management agreement, PSNC Energy receives storage asset management feesof which 75% are credited to rate payers. No fees are received under the supply service agreement. This agreement expires on March 31, 2017.

Income Statement policy [Policy Text Block]

Income Statement Presentation

Revenues and expenses arising from regulated businesses and, in the case of the Company, retail natural gas marketing businesses (including those activities of segments described in Note 10) are presented within operating income, and all other activities are presented within other income (expense). Consistent with this presentation, the Company presents the 2015 gain on the sale of CGT within operating income and the 2015 gain on the sale of SCI within other income (expense).

New Accounting Pronouncements, Policy [Policy Text Block]

New Accounting Matters

In May 2014, the FASB issued accounting guidance for revenue arising from contracts with customers that supersedes most current revenue recognition guidance, including industry-specific guidance. This revenue recognition model provides a

five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the

transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive

in exchange for those goods or services. This guidance must be adopted no later than the first quarter of 2018, and early

adoption is permitted in the first quarter of 2017. Adoption using a retrospective method is required, with options to elect

certain practical expedients or to recognize a cumulative effect in the year of initial adoption. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what practical expedients will be elected. The Company and Consolidated SCE&G have not determined the impact this guidance will have on their respective financial statements.

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. This guidance was adopted in the first quarter of 2016 and had no impact on the Company’s or Consolidated SCE&G's financial statements.

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 and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2017. The Company and Consolidated SCE&G are evaluating this guidance and have not determined what impact it will have on their respective financial statements.

In January 2016, the FASB issued accounting guidance intended to clarify the classification and measurement of financial instruments and financial liabilities, among other things. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018. The Company and Consolidated SCE&G are evaluating this guidance and have not determined what impact it will have on their respective financial statements.

In February 2016, the FASB issued accounting guidance related to the recognition, measurement and presentation of

leases. The guidance applies a right-of-use model and, for lessees, requires all leases with a duration over twelve months to be

recorded on the balance sheet, with the rights of use treated as assets and the payment obligations treated as liabilities. Further,

and without consideration of any regulatory accounting requirements which may apply, depending primarily of the nature of the

assets and the relative consumption of them, lease costs will be recognized either through the separate amortization of the right-of-use asset and the recognition of the interest cost related to the payment obligation, or through the recording of a combined

straight-line rental expense. For lessors, the guidance calls for the recognition of income either through the derecognition of

assets and subsequent recording of interest income on lease amounts receivable, or through the recognition of rental income on

a straight line basis, also depending on the nature of the assets and relative consumption. The guidance will be effective for

years beginning in 2019. The Company and Consolidated SCE&G have not determined what impact this guidance will have on their respective financial statements.

In March 2016, the FASB issued accounting guidance changing how companies account for certain aspects of share-based payments to employees. Entities will be required to recognize the income tax effects of awards in the income statement when the awards vest or are settled. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2017. The Company and Consolidated SCE&G are evaluating this guidance and have not determined what impact it will have on their respective financial statements.

SCEG

Significant Accounting Policies

Basis Of Consolidation And Variable Interest Entities [Policy Text Block]

Basis of Consolidation and Variable Interest Entities

The condensed consolidated financial statements of the Company include, after eliminating intercompany balances and transactions, the accounts of the parent holding company and each of its subsidiaries, including Consolidated SCE&G. Accordingly, discussions regarding the Company's financial results necessarily include the results of Consolidated SCE&G.

SCE&G has determined that it has a controlling financial interest in GENCO and Fuel Company (which are considered to be VIEs) and, accordingly, Consolidated SCE&G's condensed consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. As a result, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s condensed consolidated financial statements.

GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $488 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.

Income Statement policy [Policy Text Block]

Income Statement Presentation

Revenues and expenses arising from regulated businesses and, in the case of the Company, retail natural gas marketing businesses (including those activities of segments described in Note 10) are presented within operating income, and all other activities are presented within other income (expense). Consistent with this presentation, the Company presents the 2015 gain on the sale of CGT within operating income and the 2015 gain on the sale of SCI within other income (expense).

New Accounting Pronouncements, Policy [Policy Text Block]

New Accounting Matters

In May 2014, the FASB issued accounting guidance for revenue arising from contracts with customers that supersedes most current revenue recognition guidance, including industry-specific guidance. This revenue recognition model provides a

five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the

transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive

in exchange for those goods or services. This guidance must be adopted no later than the first quarter of 2018, and early

adoption is permitted in the first quarter of 2017. Adoption using a retrospective method is required, with options to elect

certain practical expedients or to recognize a cumulative effect in the year of initial adoption. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what practical expedients will be elected. The Company and Consolidated SCE&G have not determined the impact this guidance will have on their respective financial statements.

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. This guidance was adopted in the first quarter of 2016 and had no impact on the Company’s or Consolidated SCE&G's financial statements.

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 and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2017. The Company and Consolidated SCE&G are evaluating this guidance and have not determined what impact it will have on their respective financial statements.

In January 2016, the FASB issued accounting guidance intended to clarify the classification and measurement of financial instruments and financial liabilities, among other things. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018. The Company and Consolidated SCE&G are evaluating this guidance and have not determined what impact it will have on their respective financial statements.

In February 2016, the FASB issued accounting guidance related to the recognition, measurement and presentation of

leases. The guidance applies a right-of-use model and, for lessees, requires all leases with a duration over twelve months to be

recorded on the balance sheet, with the rights of use treated as assets and the payment obligations treated as liabilities. Further,

and without consideration of any regulatory accounting requirements which may apply, depending primarily of the nature of the

assets and the relative consumption of them, lease costs will be recognized either through the separate amortization of the right-of-use asset and the recognition of the interest cost related to the payment obligation, or through the recording of a combined

straight-line rental expense. For lessors, the guidance calls for the recognition of income either through the derecognition of

assets and subsequent recording of interest income on lease amounts receivable, or through the recognition of rental income on

a straight line basis, also depending on the nature of the assets and relative consumption. The guidance will be effective for

years beginning in 2019. The Company and Consolidated SCE&G have not determined what impact this guidance will have on their respective financial statements.

In March 2016, the FASB issued accounting guidance changing how companies account for certain aspects of share-based payments to employees. Entities will be required to recognize the income tax effects of awards in the income statement when the awards vest or are settled. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2017. The Company and Consolidated SCE&G are evaluating this guidance and have not determined what impact it will have on their respective financial statements.

XML

RATE AND OTHER REGULATORY MATTERS (Tables)

3 Months Ended

Mar. 31, 2016

Regulatory Assets

Schedule of Regulatory Assets [Table Text Block]

.

	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2016		December 31, 2015		March 31, 2016		December 31, 2015
Regulatory Assets:
Accumulated deferred income taxes	$	297	$	298	$	290	$	291
Environmental remediation costs	41		42		34		35
AROs and related funding	402		405		381		384
Deferred employee benefit plan costs	323		325		293		295
Deferred losses on interest rate derivatives	666		535		666		535
Unrecovered plant	125		127		125		127
DSM Programs	61		61		61		61
Other	153		144		136		129
Total Regulatory Assets	$	2,068	$	1,937	$	1,986	$	1,857

Schedule of Regulatory Liabilities [Table Text Block]

Regulatory Liabilities:
Asset removal costs	$	739	$	732	$	522	$	519
Deferred gains on interest rate derivatives	81		96		81		96
Other	27		27		20		20
Total Regulatory Liabilities	$	847	$	855	$	623	$	635

SCEG

Regulatory Assets

Schedule of Regulatory Assets [Table Text Block]

	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2016		December 31, 2015		March 31, 2016		December 31, 2015
Regulatory Assets:
Accumulated deferred income taxes	$	297	$	298	$	290	$	291
Environmental remediation costs	41		42		34		35
AROs and related funding	402		405		381		384
Deferred employee benefit plan costs	323		325		293		295
Deferred losses on interest rate derivatives	666		535		666		535
Unrecovered plant	125		127		125		127
DSM Programs	61		61		61		61
Other	153		144		136		129
Total Regulatory Assets	$	2,068	$	1,937	$	1,986	$	1,857

Schedule of Regulatory Liabilities [Table Text Block]

Regulatory Liabilities:
Asset removal costs	$	739	$	732	$	522	$	519
Deferred gains on interest rate derivatives	81		96		81		96
Other	27		27		20		20
Total Regulatory Liabilities	$	847	$	855	$	623	$	635

XML

LONG-TERM AND SHORT-TERM DEBT (Tables)

3 Months Ended

Mar. 31, 2016

Short-term Debt [Line Items]

Schedule of Line of Credit Facilities [Table Text Block]

	March 31, 2016
Millions of dollars	Total		SCANA			Consolidated SCE&G			PSNC  Energy
Lines of credit:
Five-year, expiring December 2020	$	1,300	$	400		$	700		$	200
Fuel Company five-year, expiring December 2020	$	500	—			$	500		—
Three-year, expiring December 2018	$	200	—			$	200		—
Total committed long-term	$	2,000	$	400		$	1,400		$	200
Outstanding commercial paper (270 or fewer days)	$	917	$	10		$	870		$	37
Weighted average interest rate			0.90		%	0.83		%	0.81		%
Letters of credit supported by LOC	$	3.3	$	3		$	0.3		—
Available	$	1,080	$	387		$	530		$	163

	December 31, 2015
Millions of dollars	Total		SCANA			Consolidated SCE&G			PSNC  Energy
Lines of credit:
Five-year, expiring December 2020	$	1,300	$	400		$	700		$	200
Fuel Company five-year, expiring December 2020	$	500	—			$	500		—
Three-year, expiring December 2018	$	200	—			$	200		—
Total committed long-term	$	2,000	$	400		$	1,400		$	200
Outstanding commercial paper (270 or fewer days)	$	531	$	37		$	420		$	74
Weighted average interest rate			1.19		%	0.74		%	0.77		%
Letters of credit supported by LOC	$	3.3	$	3		$	0.3		—
Available	$	1,466	$	360		$	980		$	126

SCEG

Short-term Debt [Line Items]

Schedule of Line of Credit Facilities [Table Text Block]

	March 31, 2016
Millions of dollars	Total		SCANA			Consolidated SCE&G			PSNC  Energy
Lines of credit:
Five-year, expiring December 2020	$	1,300	$	400		$	700		$	200
Fuel Company five-year, expiring December 2020	$	500	—			$	500		—
Three-year, expiring December 2018	$	200	—			$	200		—
Total committed long-term	$	2,000	$	400		$	1,400		$	200
Outstanding commercial paper (270 or fewer days)	$	917	$	10		$	870		$	37
Weighted average interest rate			0.90		%	0.83		%	0.81		%
Letters of credit supported by LOC	$	3.3	$	3		$	0.3		—
Available	$	1,080	$	387		$	530		$	163

	December 31, 2015
Millions of dollars	Total		SCANA			Consolidated SCE&G			PSNC  Energy
Lines of credit:
Five-year, expiring December 2020	$	1,300	$	400		$	700		$	200
Fuel Company five-year, expiring December 2020	$	500	—			$	500		—
Three-year, expiring December 2018	$	200	—			$	200		—
Total committed long-term	$	2,000	$	400		$	1,400		$	200
Outstanding commercial paper (270 or fewer days)	$	531	$	37		$	420		$	74
Weighted average interest rate			1.19		%	0.74		%	0.77		%
Letters of credit supported by LOC	$	3.3	$	3		$	0.3		—
Available	$	1,466	$	360		$	980		$	126

XML

DERIVATIVE FINANCIAL INSTRUMENTS (Tables)

3 Months Ended

Mar. 31, 2016

Derivative [Line Items]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

6. DERIVATIVE FINANCIAL INSTRUMENTS

Derivative instruments are recognized either as assets or liabilities in the statement of financial position and are measured at fair value. Changes in the fair value of derivative instruments are recognized either in earnings, as a component of other comprehensive income (loss) or, for regulated operations, within regulatory assets or regulatory liabilities, depending upon the intended use of the derivative and the resulting designation. 

Policies and procedures and risk limits are established to control the level of market, credit, liquidity and operational and administrative risks.  SCANA’s Board of Directors has delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and oversee and review the risk management process and infrastructure for SCANA and each of its subsidiaries.  The Risk Management Committee, which is comprised of certain officers, including the Risk Management Officer and other senior officers, apprises the Audit Committee of the Board of Directors with regard to the management of risk and brings to their attention significant areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions.

Commodity Derivatives

The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types.  Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations. Instruments designated as fair value hedges are used to mitigate exposure to fluctuating market prices created by fixed prices of stored natural gas.  The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy companies and financial institutions.  Cash settlements of commodity derivatives are classified as operating activities in the 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

Interest rate swaps may be used to manage interest rate risk and exposure to changes in fair value attributable to changes in interest rates on certain debt issuances.  In cases where swaps that are designated as cash flow hedges are used to synthetically convert variable rate debt to fixed rate debt, periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense.

Treasury rate lock or forward starting swap agreements that are designated as cash flow hedges may be used in anticipation of the issuance of debt.  Except as described in the following paragraph, the effective portions of changes in fair value and payments made or received upon termination of such agreements for regulated subsidiaries are recorded in regulatory assets or regulatory liabilities. For SCANA and the nonregulated subsidiaries, such amounts are recorded in AOCI. Such amounts are amortized to interest expense over the term of the underlying debt. Ineffective portions of fair value changes are recognized in income.

Pursuant to regulatory orders, interest rate derivatives entered into by SCE&G after October 2013 are not designated as cash flow hedges and fair value changes and settlement amounts are recorded as regulatory assets and liabilities. Settlement losses on swaps will be amortized over the lives of subsequent debt issuances and gains may be applied to under-collected fuel, may be amortized to interest expense or may be applied as otherwise directed by the SCPSC.

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)
		Retail Gas
Hedge designation	Gas Distribution	Marketing	Energy Marketing	Total
As of March 31, 2016
Commodity contracts	9,240,000	6,236,000	4,632,500	20,108,500
Energy management contracts (a)	—	—	30,994,204	30,994,204
Total (a)	9,240,000	6,236,000	35,626,704	51,102,704
As of December 31, 2015
Commodity contracts	7,530,000	7,869,000	3,973,500	19,372,500
Energy management contracts (b)	—	—	38,857,480	38,857,480
Total (b)	7,530,000	7,869,000	42,830,980	58,229,980

(a)  Includes an aggregate 1,679,289 MMBTU related to basis swap contracts in Energy Marketing.

(b)  Includes an aggregate 1,842,048 MMBTU related to basis swap contracts in Energy Marketing.

The aggregate notional amounts of the interest rate swaps were as follows:

Interest Rate Swaps
	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2016		December 31, 2015		March 31, 2016		December 31, 2015
Designated as hedging instruments	$	120.0	$	120.0	$	36.4	$	36.4
Not designated as hedging instruments	1,235.0		1,235.0		1,235.0		1,235.0

The following table shows the fair value and balance sheet location of derivative instruments. Although derivatives subject to master netting arrangements are netted on the Consolidated Balance Sheet, the fair values presented below are shown gross and cash collateral on the derivatives has not been netted against the fair values shown.

Fair Values of Derivative Instruments
		The Company				Consolidated SCE&G
Millions of dollars	Balance Sheet Location	Asset		Liability		Asset		Liability
As of March 31, 2016
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	3			$	1
	Other deferred credits and other liabilities			36				12
Commodity contracts
	Other current assets	$	1	1
	Derivative financial instruments			2
Total		$	1	$	42	—		$	13
Not designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	100			$	100
	Other deferred credits and other liabilities			83				83
Commodity contracts
	Other current assets	$	2
Energy management contracts
	Other current assets	9		1
	Other deferred debits and other assets	4
	Derivative financial instruments			9
	Other deferred credits and other liabilities			3
Total		$	15	$	196	—		$	183
As of December 31, 2015
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	4			$	1
	Other deferred credits and other liabilities			28				9
Commodity contracts
	Other current assets			1
	Derivative financial instruments			4
Total		$	—	$	37	—		$	10
Not designated as hedging instruments
Interest rate contracts
	Other current assets	$	10			$	10
	Other deferred debits and other assets	5				5
	Derivative financial instruments			$	33			$	33
	Other deferred credits and other liabilities			22				22
Commodity contracts
	Other current assets	1		2
Energy management contracts
	Other current assets	11
	Other deferred debits and other assets	3
	Derivative financial instruments			9
	Other deferred credits and other liabilities			3
Total		$	30	$	69	$	15	$	55

 The effect of derivative instruments on the condensed consolidated statements of income is as follows: 

Derivatives in Cash Flow Hedging Relationships

The Company and Consolidated SCE&G:
	Loss Deferred in Regulatory Accounts							Loss Reclassified from Deferred Accounts into Income
	(Effective Portion)							(Effective Portion)
Millions of dollars	2016			2015			Location	2016			2015
Three Months Ended March 31,
Interest rate contracts	$	(3	)	$	(2	)	Interest expense	$	(1	)	$	—

The Company:
	Loss Recognized in OCI, net of tax							Loss Reclassified from AOCI into Income, net of tax
	(Effective Portion)							(Effective Portion)
Millions of dollars	2016			2015			Location	2016			2015
Three Months Ended March 31,
Interest rate contracts	$	(3	)	$	(2	)	Interest expense	$	(2	)	$	(2	)
Commodity contracts	(2		)	(1		)	Gas purchased for resale	(5		)	(7		)
Total	$	(5	)	$	(3	)		$	(7	)	$	(9	)

As of March 31, 2016, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $1.1 million as an increase to gas cost, assuming natural gas markets remain at their current levels, and approximately $6.5 million as an increase to interest expense.  As of March 31, 2016, all of the Company’s commodity cash flow hedges settle by their terms before the end of the first quarter of 2019.

As of March 31, 2016, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $2.1 million as an increase to interest expense.

Hedge Ineffectiveness

For the Company and Consolidated SCE&G, ineffectiveness on interest rate hedges designated as cash flow hedges was insignificant during all periods presented.

Derivatives not designated as Hedging Instruments
The Company and Consolidated SCE&G:
	Loss Deferred in Regulatory Accounts							Gain Reclassified from Deferred Accounts into Income
Millions of dollars	2016			2015			Location	2016		2015
Three Months Ended March 31,
Interest rate contracts	$	(144	)	$	(94	)	Other income	$	—	$	4

As of March 31, 2016, the Company and Consolidated SCE&G expect that during the next 12 months reclassifications from regulatory accounts to earnings arising from derivatives not designated as hedges will include $0.7 million as an increase to interest expense.

Credit Risk Considerations

Certain derivative contracts contain contingent credit features. These features may include (i) material adverse change clauses or payment acceleration clauses that could result in immediate payments or (ii) the posting of letters of credit or termination of the derivative contract before maturity if specific events occur, such as a credit rating downgrade below investment grade or failure to post collateral.

Derivative Contracts with Credit Contingent Features
	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2016		December 31, 2015		March 31, 2016		December 31, 2015
in Net Liability Position
Aggregate fair value of derivatives in net liability position	$	234.1	$	95.2	$	196.1	$	57.0
Fair value of collateral already posted	124.1		50.4		88.2		13.4
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	110.0		44.8		107.9		43.6
in Net Asset Position
Aggregate fair value of derivatives in net asset position	$	—	$	7.3	$	—	$	7.3
Fair value of collateral already posted	—		—		—		—
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	—		7.3		—		7.3

In addition, for fixed price supply contracts offered to certain of SEMI's customers, the Company could have called on letters of credit in the amount of $3.0 million related to $13.0 million in commodity derivatives that are in a net asset position at March 31, 2016, compared to letters of credit of $3.0 million related to derivatives of $14.0 million at December 31, 2015, if all the contingent features underlying these instruments had been fully triggered.

Information related to the offsetting of derivative assets follows:

Derivative Assets	The Company												Consolidated SCE&G
Millions of dollars	Interest Rate Contracts			Commodity Contracts			Energy Management Contracts			Total			Interest Rate Contracts
As of March 31, 2016
Gross Amounts of Recognized Assets	—			$	3		$	13		$	16		—
Gross Amounts Offset in Statement of Financial Position	—			(1		)	—			(1		)	—
Net Amounts Presented in Statement of Financial Position	—			2			13			15			—
Gross Amounts Not Offset - Financial Instruments	—			—			—			—			—
Gross Amounts Not Offset - Cash Collateral Received	—			—			—			—			—
Net Amount	—			$	2		$	13		$	15		—
Balance sheet location
Other current assets										$	11		—
Other deferred debits and other assets										4			—
Total										$	15		—
As of December 31, 2015
Gross Amounts of Recognized Assets	$	15		$	1		$	15		$	31		$	15
Gross Amounts Offset in Statement of Financial Position	—			—			(1		)	(1		)	—
Net Amounts Presented in Statement of Financial Position	15			1			14			30			15
Gross Amounts Not Offset - Financial Instruments	(8		)	—			—			(8		)	(8		)
Gross Amounts Not Offset - Cash Collateral Received	—			—			—			—			—
Net Amount	$	7		$	1		$	14		$	22		$	7
Balance sheet location
Other current assets										$	22		$	10
Other deferred debits and other assets										8			5
Total										$	30		$	15

Information related to the offsetting of derivative liabilities follows:

Derivative Liabilities	The Company												Consolidated SCE&G
Millions of dollars	Interest Rate Contracts			Commodity Contracts			Energy Management Contracts			Total			Interest Rate Contracts
As of March 31, 2016
Gross Amounts of Recognized Liabilities	$	222		$	3		$	13		$	238		$	196
Gross Amounts Offset in Statement of Financial Position	—			(1		)	—			(1		)	—
Net Amounts Presented in Statement of Financial Position	222			2			13			237			196
Gross Amounts Not Offset - Financial Instruments	—			—			—			—			—
Gross Amounts Not Offset - Cash Collateral Posted	(116		)	(2		)	(6		)	(124		)	(88		)
Net Amount	$	106		$	—		$	7		$	113		$	108
Balance sheet location
Other current assets										$	2		—
Derivative financial instruments										113			$	101
Other deferred credits and other liabilities										122			95
Total										$	237		$	196
As of December 31, 2015
Gross Amounts of Recognized Liabilities	$	87		$	5		$	15		$	107		$	65
Gross Amounts Offset in Statement of Financial Position	—			—			(1		)	(1		)	—
Net Amounts Presented in Statement of Financial Position	87			5			14			106			65
Gross Amounts Not Offset - Financial Instruments	(8		)	—			—			(8		)	(8		)
Gross Amounts Not Offset - Cash Collateral Posted	(36		)	(5		)	(9		)	(50		)	(13		)
Net Amount	$	43		$	—		$	5		$	48		$	44
Balance sheet location
Other current assets										$	3		—
Derivative financial instruments										50			$	34
Other deferred credits and other liabilities										53			31
Total										$	106		$	65

Schedule of Nonmonetary Notional Amounts of Outstanding Derivative Positions [Table Text Block]

The Company was party to natural gas derivative contracts outstanding in the following quantities:

	Commodity and Other Energy Management Contracts (in MMBTU)
		Retail Gas
Hedge designation	Gas Distribution	Marketing	Energy Marketing	Total
As of March 31, 2016
Commodity contracts	9,240,000	6,236,000	4,632,500	20,108,500
Energy management contracts (a)	—	—	30,994,204	30,994,204
Total (a)	9,240,000	6,236,000	35,626,704	51,102,704
As of December 31, 2015
Commodity contracts	7,530,000	7,869,000	3,973,500	19,372,500
Energy management contracts (b)	—	—	38,857,480	38,857,480
Total (b)	7,530,000	7,869,000	42,830,980	58,229,980

(a)  Includes an aggregate 1,679,289 MMBTU related to basis swap contracts in Energy Marketing.

(b)  Includes an aggregate 1,842,048 MMBTU related to basis swap contracts in Energy Marketing.

Schedule of Derivative Instruments [Table Text Block]

The aggregate notional amounts of the interest rate swaps were as follows:

Interest Rate Swaps
	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2016		December 31, 2015		March 31, 2016		December 31, 2015
Designated as hedging instruments	$	120.0	$	120.0	$	36.4	$	36.4
Not designated as hedging instruments	1,235.0		1,235.0		1,235.0		1,235.0

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

The following table shows the fair value and balance sheet location of derivative instruments. Although derivatives subject to master netting arrangements are netted on the Consolidated Balance Sheet, the fair values presented below are shown gross and cash collateral on the derivatives has not been netted against the fair values shown.

Fair Values of Derivative Instruments
		The Company				Consolidated SCE&G
Millions of dollars	Balance Sheet Location	Asset		Liability		Asset		Liability
As of March 31, 2016
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	3			$	1
	Other deferred credits and other liabilities			36				12
Commodity contracts
	Other current assets	$	1	1
	Derivative financial instruments			2
Total		$	1	$	42	—		$	13
Not designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	100			$	100
	Other deferred credits and other liabilities			83				83
Commodity contracts
	Other current assets	$	2
Energy management contracts
	Other current assets	9		1
	Other deferred debits and other assets	4
	Derivative financial instruments			9
	Other deferred credits and other liabilities			3
Total		$	15	$	196	—		$	183
As of December 31, 2015
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	4			$	1
	Other deferred credits and other liabilities			28				9
Commodity contracts
	Other current assets			1
	Derivative financial instruments			4
Total		$	—	$	37	—		$	10
Not designated as hedging instruments
Interest rate contracts
	Other current assets	$	10			$	10
	Other deferred debits and other assets	5				5
	Derivative financial instruments			$	33			$	33
	Other deferred credits and other liabilities			22				22
Commodity contracts
	Other current assets	1		2
Energy management contracts
	Other current assets	11
	Other deferred debits and other assets	3
	Derivative financial instruments			9
	Other deferred credits and other liabilities			3
Total		$	30	$	69	$	15	$	55

Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]

Derivatives in Cash Flow Hedging Relationships

The Company and Consolidated SCE&G:
	Loss Deferred in Regulatory Accounts							Loss Reclassified from Deferred Accounts into Income
	(Effective Portion)							(Effective Portion)
Millions of dollars	2016			2015			Location	2016			2015
Three Months Ended March 31,
Interest rate contracts	$	(3	)	$	(2	)	Interest expense	$	(1	)	$	—

The Company:
	Loss Recognized in OCI, net of tax							Loss Reclassified from AOCI into Income, net of tax
	(Effective Portion)							(Effective Portion)
Millions of dollars	2016			2015			Location	2016			2015
Three Months Ended March 31,
Interest rate contracts	$	(3	)	$	(2	)	Interest expense	$	(2	)	$	(2	)
Commodity contracts	(2		)	(1		)	Gas purchased for resale	(5		)	(7		)
Total	$	(5	)	$	(3	)		$	(7	)	$	(9	)

Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]

Derivatives not designated as Hedging Instruments
The Company and Consolidated SCE&G:
	Loss Deferred in Regulatory Accounts							Gain Reclassified from Deferred Accounts into Income
Millions of dollars	2016			2015			Location	2016		2015
Three Months Ended March 31,
Interest rate contracts	$	(144	)	$	(94	)	Other income	$	—	$	4

Disclosure of Credit Derivatives [Table Text Block]

Derivative Contracts with Credit Contingent Features
	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2016		December 31, 2015		March 31, 2016		December 31, 2015
in Net Liability Position
Aggregate fair value of derivatives in net liability position	$	234.1	$	95.2	$	196.1	$	57.0
Fair value of collateral already posted	124.1		50.4		88.2		13.4
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	110.0		44.8		107.9		43.6
in Net Asset Position
Aggregate fair value of derivatives in net asset position	$	—	$	7.3	$	—	$	7.3
Fair value of collateral already posted	—		—		—		—
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	—		7.3		—		7.3

Offseting Assets [Table Text Block]

Information related to the offsetting of derivative assets follows:

Derivative Assets	The Company												Consolidated SCE&G
Millions of dollars	Interest Rate Contracts			Commodity Contracts			Energy Management Contracts			Total			Interest Rate Contracts
As of March 31, 2016
Gross Amounts of Recognized Assets	—			$	3		$	13		$	16		—
Gross Amounts Offset in Statement of Financial Position	—			(1		)	—			(1		)	—
Net Amounts Presented in Statement of Financial Position	—			2			13			15			—
Gross Amounts Not Offset - Financial Instruments	—			—			—			—			—
Gross Amounts Not Offset - Cash Collateral Received	—			—			—			—			—
Net Amount	—			$	2		$	13		$	15		—
Balance sheet location
Other current assets										$	11		—
Other deferred debits and other assets										4			—
Total										$	15		—
As of December 31, 2015
Gross Amounts of Recognized Assets	$	15		$	1		$	15		$	31		$	15
Gross Amounts Offset in Statement of Financial Position	—			—			(1		)	(1		)	—
Net Amounts Presented in Statement of Financial Position	15			1			14			30			15
Gross Amounts Not Offset - Financial Instruments	(8		)	—			—			(8		)	(8		)
Gross Amounts Not Offset - Cash Collateral Received	—			—			—			—			—
Net Amount	$	7		$	1		$	14		$	22		$	7
Balance sheet location
Other current assets										$	22		$	10
Other deferred debits and other assets										8			5
Total										$	30		$	15

Offsetting Liabilities [Table Text Block]

Information related to the offsetting of derivative liabilities follows:

Derivative Liabilities	The Company												Consolidated SCE&G
Millions of dollars	Interest Rate Contracts			Commodity Contracts			Energy Management Contracts			Total			Interest Rate Contracts
As of March 31, 2016
Gross Amounts of Recognized Liabilities	$	222		$	3		$	13		$	238		$	196
Gross Amounts Offset in Statement of Financial Position	—			(1		)	—			(1		)	—
Net Amounts Presented in Statement of Financial Position	222			2			13			237			196
Gross Amounts Not Offset - Financial Instruments	—			—			—			—			—
Gross Amounts Not Offset - Cash Collateral Posted	(116		)	(2		)	(6		)	(124		)	(88		)
Net Amount	$	106		$	—		$	7		$	113		$	108
Balance sheet location
Other current assets										$	2		—
Derivative financial instruments										113			$	101
Other deferred credits and other liabilities										122			95
Total										$	237		$	196
As of December 31, 2015
Gross Amounts of Recognized Liabilities	$	87		$	5		$	15		$	107		$	65
Gross Amounts Offset in Statement of Financial Position	—			—			(1		)	(1		)	—
Net Amounts Presented in Statement of Financial Position	87			5			14			106			65
Gross Amounts Not Offset - Financial Instruments	(8		)	—			—			(8		)	(8		)
Gross Amounts Not Offset - Cash Collateral Posted	(36		)	(5		)	(9		)	(50		)	(13		)
Net Amount	$	43		$	—		$	5		$	48		$	44
Balance sheet location
Other current assets										$	3		—
Derivative financial instruments										50			$	34
Other deferred credits and other liabilities										53			31
Total										$	106		$	65

SCEG

Derivative [Line Items]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

DERIVATIVE FINANCIAL INSTRUMENTS

Derivative instruments are recognized either as assets or liabilities in the statement of financial position and are measured at fair value. Changes in the fair value of derivative instruments are recognized either in earnings, as a component of other comprehensive income (loss) or, for regulated operations, within regulatory assets or regulatory liabilities, depending upon the intended use of the derivative and the resulting designation. 

Policies and procedures and risk limits are established to control the level of market, credit, liquidity and operational and administrative risks.  SCANA’s Board of Directors has delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and oversee and review the risk management process and infrastructure for SCANA and each of its subsidiaries.  The Risk Management Committee, which is comprised of certain officers, including the Risk Management Officer and other senior officers, apprises the Audit Committee of the Board of Directors with regard to the management of risk and brings to their attention significant areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions.

Commodity Derivatives

The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types.  Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations. Instruments designated as fair value hedges are used to mitigate exposure to fluctuating market prices created by fixed prices of stored natural gas.  The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy companies and financial institutions.  Cash settlements of commodity derivatives are classified as operating activities in the 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

Interest rate swaps may be used to manage interest rate risk and exposure to changes in fair value attributable to changes in interest rates on certain debt issuances.  In cases where swaps that are designated as cash flow hedges are used to synthetically convert variable rate debt to fixed rate debt, periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense.

Treasury rate lock or forward starting swap agreements that are designated as cash flow hedges may be used in anticipation of the issuance of debt.  Except as described in the following paragraph, the effective portions of changes in fair value and payments made or received upon termination of such agreements for regulated subsidiaries are recorded in regulatory assets or regulatory liabilities. For SCANA and the nonregulated subsidiaries, such amounts are recorded in AOCI. Such amounts are amortized to interest expense over the term of the underlying debt. Ineffective portions of fair value changes are recognized in income.

Pursuant to regulatory orders, interest rate derivatives entered into by SCE&G after October 2013 are not designated as cash flow hedges and fair value changes and settlement amounts are recorded as regulatory assets and liabilities. Settlement losses on swaps will be amortized over the lives of subsequent debt issuances and gains may be applied to under-collected fuel, may be amortized to interest expense or may be applied as otherwise directed by the SCPSC.

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)
		Retail Gas
Hedge designation	Gas Distribution	Marketing	Energy Marketing	Total
As of March 31, 2016
Commodity contracts	9,240,000	6,236,000	4,632,500	20,108,500
Energy management contracts (a)	—	—	30,994,204	30,994,204
Total (a)	9,240,000	6,236,000	35,626,704	51,102,704
As of December 31, 2015
Commodity contracts	7,530,000	7,869,000	3,973,500	19,372,500
Energy management contracts (b)	—	—	38,857,480	38,857,480
Total (b)	7,530,000	7,869,000	42,830,980	58,229,980

(a)  Includes an aggregate 1,679,289 MMBTU related to basis swap contracts in Energy Marketing.

(b)  Includes an aggregate 1,842,048 MMBTU related to basis swap contracts in Energy Marketing.

The aggregate notional amounts of the interest rate swaps were as follows:

Interest Rate Swaps
	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2016		December 31, 2015		March 31, 2016		December 31, 2015
Designated as hedging instruments	$	120.0	$	120.0	$	36.4	$	36.4
Not designated as hedging instruments	1,235.0		1,235.0		1,235.0		1,235.0

The following table shows the fair value and balance sheet location of derivative instruments. Although derivatives subject to master netting arrangements are netted on the Consolidated Balance Sheet, the fair values presented below are shown gross and cash collateral on the derivatives has not been netted against the fair values shown.

Fair Values of Derivative Instruments
		The Company				Consolidated SCE&G
Millions of dollars	Balance Sheet Location	Asset		Liability		Asset		Liability
As of March 31, 2016
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	3			$	1
	Other deferred credits and other liabilities			36				12
Commodity contracts
	Other current assets	$	1	1
	Derivative financial instruments			2
Total		$	1	$	42	—		$	13
Not designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	100			$	100
	Other deferred credits and other liabilities			83				83
Commodity contracts
	Other current assets	$	2
Energy management contracts
	Other current assets	9		1
	Other deferred debits and other assets	4
	Derivative financial instruments			9
	Other deferred credits and other liabilities			3
Total		$	15	$	196	—		$	183
As of December 31, 2015
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	4			$	1
	Other deferred credits and other liabilities			28				9
Commodity contracts
	Other current assets			1
	Derivative financial instruments			4
Total		$	—	$	37	—		$	10
Not designated as hedging instruments
Interest rate contracts
	Other current assets	$	10			$	10
	Other deferred debits and other assets	5				5
	Derivative financial instruments			$	33			$	33
	Other deferred credits and other liabilities			22				22
Commodity contracts
	Other current assets	1		2
Energy management contracts
	Other current assets	11
	Other deferred debits and other assets	3
	Derivative financial instruments			9
	Other deferred credits and other liabilities			3
Total		$	30	$	69	$	15	$	55

 The effect of derivative instruments on the condensed consolidated statements of income is as follows: 

Derivatives in Cash Flow Hedging Relationships

The Company and Consolidated SCE&G:
	Loss Deferred in Regulatory Accounts							Loss Reclassified from Deferred Accounts into Income
	(Effective Portion)							(Effective Portion)
Millions of dollars	2016			2015			Location	2016			2015
Three Months Ended March 31,
Interest rate contracts	$	(3	)	$	(2	)	Interest expense	$	(1	)	$	—

The Company:
	Loss Recognized in OCI, net of tax							Loss Reclassified from AOCI into Income, net of tax
	(Effective Portion)							(Effective Portion)
Millions of dollars	2016			2015			Location	2016			2015
Three Months Ended March 31,
Interest rate contracts	$	(3	)	$	(2	)	Interest expense	$	(2	)	$	(2	)
Commodity contracts	(2		)	(1		)	Gas purchased for resale	(5		)	(7		)
Total	$	(5	)	$	(3	)		$	(7	)	$	(9	)

As of March 31, 2016, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $1.1 million as an increase to gas cost, assuming natural gas markets remain at their current levels, and approximately $6.5 million as an increase to interest expense.  As of March 31, 2016, all of the Company’s commodity cash flow hedges settle by their terms before the end of the first quarter of 2019.

As of March 31, 2016, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $2.1 million as an increase to interest expense.

Hedge Ineffectiveness

For the Company and Consolidated SCE&G, ineffectiveness on interest rate hedges designated as cash flow hedges was insignificant during all periods presented.

Derivatives not designated as Hedging Instruments
The Company and Consolidated SCE&G:
	Loss Deferred in Regulatory Accounts							Gain Reclassified from Deferred Accounts into Income
Millions of dollars	2016			2015			Location	2016		2015
Three Months Ended March 31,
Interest rate contracts	$	(144	)	$	(94	)	Other income	$	—	$	4

As of March 31, 2016, the Company and Consolidated SCE&G expect that during the next 12 months reclassifications from regulatory accounts to earnings arising from derivatives not designated as hedges will include $0.7 million as an increase to interest expense.

Credit Risk Considerations

Certain derivative contracts contain contingent credit features. These features may include (i) material adverse change clauses or payment acceleration clauses that could result in immediate payments or (ii) the posting of letters of credit or termination of the derivative contract before maturity if specific events occur, such as a credit rating downgrade below investment grade or failure to post collateral.

Derivative Contracts with Credit Contingent Features
	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2016		December 31, 2015		March 31, 2016		December 31, 2015
in Net Liability Position
Aggregate fair value of derivatives in net liability position	$	234.1	$	95.2	$	196.1	$	57.0
Fair value of collateral already posted	124.1		50.4		88.2		13.4
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	110.0		44.8		107.9		43.6
in Net Asset Position
Aggregate fair value of derivatives in net asset position	$	—	$	7.3	$	—	$	7.3
Fair value of collateral already posted	—		—		—		—
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	—		7.3		—		7.3

In addition, for fixed price supply contracts offered to certain of SEMI's customers, the Company could have called on letters of credit in the amount of $3.0 million related to $13.0 million in commodity derivatives that are in a net asset position at March 31, 2016, compared to letters of credit of $3.0 million related to derivatives of $14.0 million at December 31, 2015, if all the contingent features underlying these instruments had been fully triggered.

Information related to the offsetting of derivative assets follows:

Derivative Assets	The Company												Consolidated SCE&G
Millions of dollars	Interest Rate Contracts			Commodity Contracts			Energy Management Contracts			Total			Interest Rate Contracts
As of March 31, 2016
Gross Amounts of Recognized Assets	—			$	3		$	13		$	16		—
Gross Amounts Offset in Statement of Financial Position	—			(1		)	—			(1		)	—
Net Amounts Presented in Statement of Financial Position	—			2			13			15			—
Gross Amounts Not Offset - Financial Instruments	—			—			—			—			—
Gross Amounts Not Offset - Cash Collateral Received	—			—			—			—			—
Net Amount	—			$	2		$	13		$	15		—
Balance sheet location
Other current assets										$	11		—
Other deferred debits and other assets										4			—
Total										$	15		—
As of December 31, 2015
Gross Amounts of Recognized Assets	$	15		$	1		$	15		$	31		$	15
Gross Amounts Offset in Statement of Financial Position	—			—			(1		)	(1		)	—
Net Amounts Presented in Statement of Financial Position	15			1			14			30			15
Gross Amounts Not Offset - Financial Instruments	(8		)	—			—			(8		)	(8		)
Gross Amounts Not Offset - Cash Collateral Received	—			—			—			—			—
Net Amount	$	7		$	1		$	14		$	22		$	7
Balance sheet location
Other current assets										$	22		$	10
Other deferred debits and other assets										8			5
Total										$	30		$	15

Information related to the offsetting of derivative liabilities follows:

Derivative Liabilities	The Company												Consolidated SCE&G
Millions of dollars	Interest Rate Contracts			Commodity Contracts			Energy Management Contracts			Total			Interest Rate Contracts
As of March 31, 2016
Gross Amounts of Recognized Liabilities	$	222		$	3		$	13		$	238		$	196
Gross Amounts Offset in Statement of Financial Position	—			(1		)	—			(1		)	—
Net Amounts Presented in Statement of Financial Position	222			2			13			237			196
Gross Amounts Not Offset - Financial Instruments	—			—			—			—			—
Gross Amounts Not Offset - Cash Collateral Posted	(116		)	(2		)	(6		)	(124		)	(88		)
Net Amount	$	106		$	—		$	7		$	113		$	108
Balance sheet location
Other current assets										$	2		—
Derivative financial instruments										113			$	101
Other deferred credits and other liabilities										122			95
Total										$	237		$	196
As of December 31, 2015
Gross Amounts of Recognized Liabilities	$	87		$	5		$	15		$	107		$	65
Gross Amounts Offset in Statement of Financial Position	—			—			(1		)	(1		)	—
Net Amounts Presented in Statement of Financial Position	87			5			14			106			65
Gross Amounts Not Offset - Financial Instruments	(8		)	—			—			(8		)	(8		)
Gross Amounts Not Offset - Cash Collateral Posted	(36		)	(5		)	(9		)	(50		)	(13		)
Net Amount	$	43		$	—		$	5		$	48		$	44
Balance sheet location
Other current assets										$	3		—
Derivative financial instruments										50			$	34
Other deferred credits and other liabilities										53			31
Total										$	106		$	65

Schedule of Derivative Instruments [Table Text Block]

The aggregate notional amounts of the interest rate swaps were as follows:

Interest Rate Swaps
	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2016		December 31, 2015		March 31, 2016		December 31, 2015
Designated as hedging instruments	$	120.0	$	120.0	$	36.4	$	36.4
Not designated as hedging instruments	1,235.0		1,235.0		1,235.0		1,235.0

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

The following table shows the fair value and balance sheet location of derivative instruments. Although derivatives subject to master netting arrangements are netted on the Consolidated Balance Sheet, the fair values presented below are shown gross and cash collateral on the derivatives has not been netted against the fair values shown.

Fair Values of Derivative Instruments
		The Company				Consolidated SCE&G
Millions of dollars	Balance Sheet Location	Asset		Liability		Asset		Liability
As of March 31, 2016
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	3			$	1
	Other deferred credits and other liabilities			36				12
Commodity contracts
	Other current assets	$	1	1
	Derivative financial instruments			2
Total		$	1	$	42	—		$	13
Not designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	100			$	100
	Other deferred credits and other liabilities			83				83
Commodity contracts
	Other current assets	$	2
Energy management contracts
	Other current assets	9		1
	Other deferred debits and other assets	4
	Derivative financial instruments			9
	Other deferred credits and other liabilities			3
Total		$	15	$	196	—		$	183
As of December 31, 2015
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	4			$	1
	Other deferred credits and other liabilities			28				9
Commodity contracts
	Other current assets			1
	Derivative financial instruments			4
Total		$	—	$	37	—		$	10
Not designated as hedging instruments
Interest rate contracts
	Other current assets	$	10			$	10
	Other deferred debits and other assets	5				5
	Derivative financial instruments			$	33			$	33
	Other deferred credits and other liabilities			22				22
Commodity contracts
	Other current assets	1		2
Energy management contracts
	Other current assets	11
	Other deferred debits and other assets	3
	Derivative financial instruments			9
	Other deferred credits and other liabilities			3
Total		$	30	$	69	$	15	$	55

Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]

Derivatives in Cash Flow Hedging Relationships

The Company and Consolidated SCE&G:
	Loss Deferred in Regulatory Accounts							Loss Reclassified from Deferred Accounts into Income
	(Effective Portion)							(Effective Portion)
Millions of dollars	2016			2015			Location	2016			2015
Three Months Ended March 31,
Interest rate contracts	$	(3	)	$	(2	)	Interest expense	$	(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
The Company and Consolidated SCE&G:
	Loss Deferred in Regulatory Accounts							Gain Reclassified from Deferred Accounts into Income
Millions of dollars	2016			2015			Location	2016		2015
Three Months Ended March 31,
Interest rate contracts	$	(144	)	$	(94	)	Other income	$	—	$	4

Disclosure of Credit Derivatives [Table Text Block]

Derivative Contracts with Credit Contingent Features
	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2016		December 31, 2015		March 31, 2016		December 31, 2015
in Net Liability Position
Aggregate fair value of derivatives in net liability position	$	234.1	$	95.2	$	196.1	$	57.0
Fair value of collateral already posted	124.1		50.4		88.2		13.4
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	110.0		44.8		107.9		43.6
in Net Asset Position
Aggregate fair value of derivatives in net asset position	$	—	$	7.3	$	—	$	7.3
Fair value of collateral already posted	—		—		—		—
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	—		7.3		—		7.3

Offseting Assets [Table Text Block]

Information related to the offsetting of derivative assets follows:

Derivative Assets	The Company												Consolidated SCE&G
Millions of dollars	Interest Rate Contracts			Commodity Contracts			Energy Management Contracts			Total			Interest Rate Contracts
As of March 31, 2016
Gross Amounts of Recognized Assets	—			$	3		$	13		$	16		—
Gross Amounts Offset in Statement of Financial Position	—			(1		)	—			(1		)	—
Net Amounts Presented in Statement of Financial Position	—			2			13			15			—
Gross Amounts Not Offset - Financial Instruments	—			—			—			—			—
Gross Amounts Not Offset - Cash Collateral Received	—			—			—			—			—
Net Amount	—			$	2		$	13		$	15		—
Balance sheet location
Other current assets										$	11		—
Other deferred debits and other assets										4			—
Total										$	15		—
As of December 31, 2015
Gross Amounts of Recognized Assets	$	15		$	1		$	15		$	31		$	15
Gross Amounts Offset in Statement of Financial Position	—			—			(1		)	(1		)	—
Net Amounts Presented in Statement of Financial Position	15			1			14			30			15
Gross Amounts Not Offset - Financial Instruments	(8		)	—			—			(8		)	(8		)
Gross Amounts Not Offset - Cash Collateral Received	—			—			—			—			—
Net Amount	$	7		$	1		$	14		$	22		$	7
Balance sheet location
Other current assets										$	22		$	10
Other deferred debits and other assets										8			5
Total										$	30		$	15

Offsetting Liabilities [Table Text Block]

Information related to the offsetting of derivative liabilities follows:

Derivative Liabilities	The Company												Consolidated SCE&G
Millions of dollars	Interest Rate Contracts			Commodity Contracts			Energy Management Contracts			Total			Interest Rate Contracts
As of March 31, 2016
Gross Amounts of Recognized Liabilities	$	222		$	3		$	13		$	238		$	196
Gross Amounts Offset in Statement of Financial Position	—			(1		)	—			(1		)	—
Net Amounts Presented in Statement of Financial Position	222			2			13			237			196
Gross Amounts Not Offset - Financial Instruments	—			—			—			—			—
Gross Amounts Not Offset - Cash Collateral Posted	(116		)	(2		)	(6		)	(124		)	(88		)
Net Amount	$	106		$	—		$	7		$	113		$	108
Balance sheet location
Other current assets										$	2		—
Derivative financial instruments										113			$	101
Other deferred credits and other liabilities										122			95
Total										$	237		$	196
As of December 31, 2015
Gross Amounts of Recognized Liabilities	$	87		$	5		$	15		$	107		$	65
Gross Amounts Offset in Statement of Financial Position	—			—			(1		)	(1		)	—
Net Amounts Presented in Statement of Financial Position	87			5			14			106			65
Gross Amounts Not Offset - Financial Instruments	(8		)	—			—			(8		)	(8		)
Gross Amounts Not Offset - Cash Collateral Posted	(36		)	(5		)	(9		)	(50		)	(13		)
Net Amount	$	43		$	—		$	5		$	48		$	44
Balance sheet location
Other current assets										$	3		—
Derivative financial instruments										50			$	34
Other deferred credits and other liabilities										53			31
Total										$	106		$	65

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Tables)

3 Months Ended

Mar. 31, 2016

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

 Fair value measurements, and the level within the fair value hierarchyin which the measurements fall, were as follows:

	As of March 31, 2016						As of December 31, 2015
	The Company				Consolidated SCE&G		The Company				Consolidated SCE&G
Millions of dollars	Level 1		Level 2		Level 2		Level 1		Level 2		Level 2
Assets:
Available for sale securities	$	11					$	11
Held to maturity securities			$	7
Interest rate contracts									$	15	$	15
Commodity contracts	2						1
Energy management contracts			13						14
Liabilities:
Interest rate contracts			222		$	196			87		65
Commodity contracts			2				1		4
Energy management contracts	1		13				4		12

Fair Value, by Balance Sheet Grouping [Table Text Block]

Financial instruments for which the carrying amount may not equal estimated fair value were as follows:

Long-Term Debt	March 31, 2016				December 31, 2015
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
The Company	$	5,995.4	$	6,704.5	$	5,997.6	$	6,445.7
Consolidated SCE&G	$	4,766.9	$	5,368.3	$	4,769.0	$	5,129.1

SCEG [member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

Fair value measurements, and the level within the fair value hierarchyin which the measurements fall, were as follows:

	As of March 31, 2016						As of December 31, 2015
	The Company				Consolidated SCE&G		The Company				Consolidated SCE&G
Millions of dollars	Level 1		Level 2		Level 2		Level 1		Level 2		Level 2
Assets:
Available for sale securities	$	11					$	11
Held to maturity securities			$	7
Interest rate contracts									$	15	$	15
Commodity contracts	2						1
Energy management contracts			13						14
Liabilities:
Interest rate contracts			222		$	196			87		65
Commodity contracts			2				1		4
Energy management contracts	1		13				4		12

Fair Value, by Balance Sheet Grouping [Table Text Block]

Financial instruments for which the carrying amount may not equal estimated fair value were as follows:

Long-Term Debt	March 31, 2016				December 31, 2015
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
The Company	$	5,995.4	$	6,704.5	$	5,997.6	$	6,445.7
Consolidated SCE&G	$	4,766.9	$	5,368.3	$	4,769.0	$	5,129.1

XML

EMPLOYEE BENEFIT PLANS (Tables)

3 Months Ended

Mar. 31, 2016

Pension and Other Postretirement Benefit Plans

Schedule of Net Benefit Costs [Table Text Block]

The Company	Pension Benefits						Other Postretirement Benefits
	2016			2015			2016		2015
Three months ended March 31,
Service cost	$	5.5		$	5.8		$	1.3	$	1.4
Interest cost	9.9			9.5			3.0		2.9
Expected return on assets	(14.1		)	(15.5		)	—		—
Prior service cost amortization	1.0			1.0			0.1		0.1
Amortization of actuarial losses	3.7			3.5			0.1		0.6
Net periodic benefit cost	$	6.0		$	4.3		$	4.5	$	5.0

SCEG

Pension and Other Postretirement Benefit Plans

Schedule of Net Benefit Costs [Table Text Block]

Consolidated SCE&G	Pension Benefits						Other Postretirement Benefits
	2016			2015			2016		2015
Three months ended March 31,
Service cost	$	4.5		$	4.6		$	1.0	$	1.1
Interest cost	8.4			8.0			2.5		2.3
Expected return on assets	(11.9		)	(13.0		)	—		—
Prior service cost amortization	0.8			0.8			0.1		0.1
Amortization of actuarial losses	3.1			3.0			0.1		0.4
Net periodic benefit cost	$	4.9		$	3.4		$	3.7	$	3.9

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SEGMENT OF BUSINESS INFORMATION (Tables)

3 Months Ended

Mar. 31, 2016

Segment Reporting Information [Line Items]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

The Company
Millions of dollars	External Revenue		Intersegment Revenue			Operating Income		Net Income
Three Months Ended March 31, 2016
Electric Operations	$	592	$	1		$	198	n/a
Gas Distribution	299		1			94		n/a
Retail Gas Marketing	171		—			n/a		$	22
Energy Marketing	110		22			n/a		2
All Other	—		98			—		—
Adjustments/Eliminations	—		(122		)	39		152
Consolidated Total	$	1,172	$	—		$	331	$	176

Three Months Ended March 31, 2015
Electric Operations	$	629		—			$	199	n/a
Gas Distribution	368			—			96		n/a
Retail Gas Marketing	204			—			n/a		$	27
Energy Marketing	187			$	35		n/a		6
All Other	4			114			238		207
Adjustments/Eliminations	(3		)	(149		)	53		160
Consolidated Total	$	1,389		$	—		$	586	$	400

Consolidated SCE&G
Millions of dollars	External Revenue		Operating Income		Earnings Available to Common Shareholder
Three Months Ended March 31, 2016
Electric Operations	$	593	$	198	n/a
Gas Distributions	124		38		n/a
Adjustments/Eliminations	—		—		$	113
Consolidated Total	$	717	$	236	$	113

Three Months Ended March 31, 2015
Electric Operations	$	630	$	199	n/a
Gas Distributions	142		38		n/a
Adjustments/Eliminations	—		—		$	122
Consolidated Total	$	772	$	237	$	122

Segment Assets	The Company				Consolidated SCE&G
	March 31,		December 31,		March 31,		December 31,
Millions of dollars	2016		2015		2016		2015
Electric Operations	$	11,039	$	10,883	$	11,039	$	10,883
Gas Distribution	2,676		2,606		768		757
Retail Gas Marketing	140		106		n/a		n/a
Energy Marketing	84		95		n/a		n/a
All Other	994		998		n/a		n/a
Adjustments/Eliminations	2,435		2,458		3,125		3,125
Consolidated Total	$	17,368	$	17,146	$	14,932	$	14,765

SCEG

Segment Reporting Information [Line Items]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

Consolidated SCE&G
Millions of dollars	External Revenue		Operating Income		Earnings Available to Common Shareholder
Three Months Ended March 31, 2016
Electric Operations	$	593	$	198	n/a
Gas Distributions	124		38		n/a
Adjustments/Eliminations	—		—		$	113
Consolidated Total	$	717	$	236	$	113

Three Months Ended March 31, 2015
Electric Operations	$	630	$	199	n/a
Gas Distributions	142		38		n/a
Adjustments/Eliminations	—		—		$	122
Consolidated Total	$	772	$	237	$	122

Segment Assets	The Company				Consolidated SCE&G
	March 31,		December 31,		March 31,		December 31,
Millions of dollars	2016		2015		2016		2015
Electric Operations	$	11,039	$	10,883	$	11,039	$	10,883
Gas Distribution	2,676		2,606		768		757
Retail Gas Marketing	140		106		n/a		n/a
Energy Marketing	84		95		n/a		n/a
All Other	994		998		n/a		n/a
Adjustments/Eliminations	2,435		2,458		3,125		3,125
Consolidated Total	$	17,368	$	17,146	$	14,932	$	14,765

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details)	3 Months Ended	12 Months Ended
	Mar. 31, 2016 USD ($) MW	Dec. 31, 2015 USD ($)
Significant Accounting Policies
Pre-tax gain on sale of CGT and SCI		$ 342,000,000
Property, Plant and Equipment, Net	$ 280,000,000	280,000,000
Reclassifications, Cash Flow Statement, Regulatory Assets, Use Of Cash	96,000,000
Reclassifications, Cash Flow Statement, Derivative Financial Instruments, Source Of Cash	81,000,000
Reclassifications, Cash Flow Statement, Other Liabilities, Source Of Cash	(15,000,000)
SCEG
Significant Accounting Policies
Property, Plant and Equipment, Net	68,000,000	$ 68,000,000
Reclassifications, Cash Flow Statement, Regulatory Assets, Use Of Cash	96,000,000
Reclassifications, Cash Flow Statement, Derivative Financial Instruments, Source Of Cash	81,000,000
Reclassifications, Cash Flow Statement, Other Liabilities, Source Of Cash	$ (15,000,000)
Genco
Significant Accounting Policies
Power Generation Capacity Megawatts | MW	605
Property, Plant and Equipment, Net	$ 488,000,000
PSNC Energy [Member]
Significant Accounting Policies
Percentage of natural gas inventory held by counterparties under asset management and supply service agreements (as a percent)	29.00%	46.00%
Natural gas inventory, carrying amount	$ 6,000,000	$ 17,700,000
PercentOfStorageFeesCreditedToRatePayers	75.00%

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RATE AND OTHER REGULATORY MATTERS (Details)	3 Months Ended		12 Months Ended
	Mar. 31, 2016 USD ($) MW	Mar. 31, 2015 USD ($)	Dec. 31, 2013	Dec. 31, 2015 USD ($)
Rate Matters [Line Items]
Reclassifications, Cash Flow Statement, Regulatory Assets, Use Of Cash	$ 96,000,000
Carrying cost recovery	(4,000,000)	$ (3,000,000)
Regulatory Assets, Noncurrent	$ 2,068,000,000			$ 1,937,000,000
MPG environmental remediation	24
PSNC Energy Rate Case Application, Increase Amount	$ 41,600,000
PSNC Energy Rate Case Application, Percentage Increase	0.00%
SCEG
Rate Matters [Line Items]
Reclassifications, Cash Flow Statement, Regulatory Assets, Use Of Cash	$ 96,000,000
Capacity of renewable energy facilities by 2020 | MW	80
Capacity of renewable energy facilities by 2016 | MW	30
SCPSC Order Reduction Of Total Fuel Cost Component Of Retail Electric Rates To Reflect Lower Projected Fuel Costs And Eliminate Over-Collection Balances	$ 61,000,000
SCPSC Order, Recovery Of Projected DER Program Costs	6,900,000
Carrying costs on deferred income tax assets	3,100,000	1,900,000
Carrying cost recovery	(4,000,000)	$ (3,000,000)
Regulatory Assets, Noncurrent	$ 1,986,000,000			1,857,000,000
Demand side management recovery period	5
SCPSC Order, Annual DSM Program Rate Rider Recovery Amount	$ 37,600,000
Environmental Restoration Costs [Member]
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	41,000,000			42,000,000
Environmental Restoration Costs [Member] | SCEG
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	$ 34,000,000			35,000,000
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
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
Pension Costs [Member]
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	323,000,000			325,000,000
Pension Costs [Member] | SCEG
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	$ 293,000,000			295,000,000
Regulatory Noncurrent Asset Amortization Period	12 years
Other Regulatory Assets [Member]
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	$ 153,000,000			144,000,000
Regulatory Noncurrent Asset Amortization Period	30 years
Other Regulatory Assets [Member] | SCEG
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	$ 136,000,000			$ 129,000,000

XML

RATE AND OTHER REGULATORY MATTERS (Details 2) $ in Millions	3 Months Ended
	Mar. 31, 2016 USD ($)	Mar. 31, 2015 USD ($)	Dec. 31, 2015 USD ($)
Regulatory Assets
Regulatory Liabilities	$ 847.0		$ 855.0
MPG environmental remediation	24
Regulatory Assets, Noncurrent	$ 2,068.0		1,937.0
SCEG
Regulatory Assets
Regulatory Liabilities	623.0		635.0
Carrying costs on deferred income tax assets	3.1	$ 1.9
Regulatory Assets, Noncurrent	$ 1,986.0		1,857.0
Demand side management recovery period	5
Other Regulatory Liability [Member]
Regulatory Assets
Regulatory Liabilities	$ 27.0		27.0
Other Regulatory Liability [Member] | SCEG
Regulatory Assets
Regulatory Liabilities	20.0		20.0
Asset Retirement Obligation Costs [Member]
Regulatory Assets
Regulatory Liabilities	739.0		732.0
Asset Retirement Obligation Costs [Member] | SCEG
Regulatory Assets
Regulatory Liabilities	522.0		519.0
Deferred gains on interest rate derivatives [Member]
Regulatory Assets
Regulatory Liabilities	81.0		96.0
Deferred gains on interest rate derivatives [Member] | SCEG
Regulatory Assets
Regulatory Liabilities	$ 81.0		96.0
Pension costs, electric [Member] | SCEG
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period	30 years
Deferred Losses On Interest Rate Derivatives [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	$ 666.0		535.0
Deferred Losses On Interest Rate Derivatives [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	$ 666.0		535.0
Asset Retirement Obligation Costs [Member]
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period	110 years
Regulatory Assets, Noncurrent	$ 402.0		405.0
Asset Retirement Obligation Costs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	381.0		384.0
unrecovered plant [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	125.0		127.0
unrecovered plant [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	125.0		127.0
Demand Side Management programs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	61.0		61.0
Demand Side Management programs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	$ 61.0		61.0
Deferred Income Tax Charges [Member]
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period	85 years
Regulatory Assets, Noncurrent	$ 297.0		298.0
Deferred Income Tax Charges [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	290.0		291.0
Environmental Restoration Costs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	41.0		42.0
Environmental Restoration Costs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	34.0		35.0
Pension Costs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	$ 323.0		325.0
Pension Costs [Member] | SCEG
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period	12 years
Regulatory Assets, Noncurrent	$ 293.0		295.0
Other Regulatory Assets [Member]
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period	30 years
Regulatory Assets, Noncurrent	$ 153.0		144.0
Other Regulatory Assets [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	$ 136.0		$ 129.0

XML

RATE AND OTHER REGULATORY MATTERS (Details 3) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Regulatory Liabilities [Line Items]
Regulatory Assets, Noncurrent	$ 2,068	$ 1,937
Regulatory Liabilities	847	855
SCEG
Regulatory Liabilities [Line Items]
Regulatory Assets, Noncurrent	1,986	1,857
Regulatory Liabilities	623	635
Asset Retirement Obligation Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	739	732
Asset Retirement Obligation Costs [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	522	519
Deferred gains on interest rate derivatives [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	81	96
Deferred gains on interest rate derivatives [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 81	$ 96

XML

COMMON EQUITY (Details) - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Schedule of Capitalization, Equity [Line Items]
Dividends, Common Stock	$ 82
Common Stock, Shares Authorized	200.0		200.0
COMMON EQUITY [Abstract]
Common Stock, Shares, Outstanding	142.9		142.9
Other Comprehensive Income (Loss), Net of Tax	$ 2	$ 2
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	2	6
SCEG
Schedule of Capitalization, Equity [Line Items]
Dividends	74	70
Dividends, Common Stock	$ 74	71
Common Stock, Shares Authorized	50.0		50.0
COMMON EQUITY [Abstract]
Common Stock, Shares, Outstanding	40.3		40.3
Preferred Stock, Shares Authorized	20.0		20.0
Preferred Stock, Shares Outstanding	0.0		0.0
SCEG excluding VIEs [Member]
Schedule of Capitalization, Equity [Line Items]
Dividends	$ 72	69
Commodity Contract
Schedule of Capitalization, Equity [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(5)	(7)
Interest Rate Contract [Member]
Schedule of Capitalization, Equity [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(2)	(2)
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	5	7
Interest Expense [Member] | Cash Flow Hedging [Member] | Interest Rate Contract [Member]
Schedule of Capitalization, Equity [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 2	$ 2

XML

LONG-TERM AND SHORT-TERM DEBT (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 2,000.0	$ 2,000.0
Long-Term Line of Credit - SC Fuel Co only	500.0	500.0
Commercial Paper	917.0	531.0
Letters of Credit Outstanding, Amount	3.3	3.3
Line of Credit Facility, Remaining Borrowing Capacity	1,080.0	1,466.0
Debt Instrument, Face Amount	67.8
SCE&G (including Fuel Company)
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	1,400.0	1,400.0
Commercial Paper	$ 870.0	$ 420.0
Debt, Weighted Average Interest Rate	0.83%	0.74%
Letters of Credit Outstanding, Amount	$ 0.3	$ 0.3
Line of Credit Facility, Remaining Borrowing Capacity	530.0	980.0
SCEG
Debt Instrument [Line Items]
Debt Instrument, Face Amount	67.8
SCANA [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	400.0	400.0
Commercial Paper	$ 10.0	$ 37.0
Debt, Weighted Average Interest Rate	0.90%	1.19%
Letters of Credit Outstanding, Amount	$ 3.0	$ 3.0
Line of Credit Facility, Remaining Borrowing Capacity	387.0	360.0
PSNC Energy [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	200.0	200.0
Commercial Paper	$ 37.0	$ 74.0
Debt, Weighted Average Interest Rate	0.81%	0.77%
Line of Credit Facility, Remaining Borrowing Capacity	$ 163.0	$ 126.0
Fuel Company
Debt Instrument [Line Items]
Long-Term Line of Credit - SC Fuel Co only	500.0	500.0
Expires December 2020 [Domain]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	1,300.0	1,300.0
Expires December 2020 [Domain] | SCEG
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	700.0	700.0
Expires December 2020 [Domain] | SCANA [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	400.0	400.0
Expires December 2020 [Domain] | PSNC Energy [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	200.0	200.0
Expires December 2016 [Domain]
Debt Instrument [Line Items]
Long-term Line of Credit - SCE&G only	200.0	200.0
Expires December 2016 [Domain] | SCEG
Debt Instrument [Line Items]
Long-term Line of Credit - SCE&G only	$ 200.0	$ 200.0

XML

LONG-TERM AND SHORT-TERM DEBT (Details 2) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
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	2,000.0	$ 2,000.0
Commercial Paper	917.0	531.0
Long-Term Line of Credit - SC Fuel Co only	500.0	500.0
Letters of credit supported by LOC	(3.3)	(3.3)
Line of Credit Facility, Remaining Borrowing Capacity	1,080.0	1,466.0
SCANA [Member]
Lines of credit:
Line of Credit Facility, Maximum Borrowing Capacity	400.0	400.0
Commercial Paper	$ 10.0	$ 37.0
Commercial paper, weighted average interest rate (as a percent)	0.90%	1.19%
Letters of credit supported by LOC	$ (3.0)	$ (3.0)
Line of Credit Facility, Remaining Borrowing Capacity	387.0	360.0
SCEG
Debt Instrument [Line Items]
Due to Affiliate, Current	116.0	113.0
Debt Instruments [Abstract]
Face value of Industrial Revenue Bonds issued, proceeds of which were availed as loan	67.8
Lines of credit:
Related Party Transaction, Due from (to) Related Party, Current	43.9	33.0
Due from Other Related Parties, Current		9.0
SCE&G (including Fuel Company)
Lines of credit:
Line of Credit Facility, Maximum Borrowing Capacity	1,400.0	1,400.0
Commercial Paper	$ 870.0	$ 420.0
Commercial paper, weighted average interest rate (as a percent)	0.83%	0.74%
Letters of credit supported by LOC	$ (0.3)	$ (0.3)
Line of Credit Facility, Remaining Borrowing Capacity	530.0	980.0
Fuel Company
Lines of credit:
Long-Term Line of Credit - SC Fuel Co only	500.0	500.0
PSNC Energy
Lines of credit:
Line of Credit Facility, Maximum Borrowing Capacity	200.0	200.0
Commercial Paper	$ 37.0	$ 74.0
Commercial paper, weighted average interest rate (as a percent)	0.81%	0.77%
Line of Credit Facility, Remaining Borrowing Capacity	$ 163.0	$ 126.0

XML

INCOME TAXES (Details) $ in Millions	Mar. 31, 2016 USD ($)
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	$ 49
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	17
Significant (Increase) Decrease in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Lower Bound	7
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	49
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	17
Significant (Increase) Decrease in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Lower Bound	7
Significant (Increase) Decrease in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Upper Bound	$ 8

XML

DERIVATIVE FINANCIAL INSTRUMENTS (Details)	3 Months Ended	12 Months Ended
	Mar. 31, 2016 USD ($) MMBTU	Dec. 31, 2015 MMBTU
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	51,102,704	58,229,980
Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	9,240,000	7,530,000
Retail Gas Marketing
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	6,236,000	7,869,000
Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	35,626,704	42,830,980
Commodity Contract
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	20,108,500	19,372,500
Commodity Contract | Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	9,240,000	7,530,000
Commodity Contract | Retail Gas Marketing
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	6,236,000	7,869,000
Commodity Contract | Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	4,632,500	3,973,500
Energy Related Derivative [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	30,994,204	38,857,480
Energy Related Derivative [Member] | Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	30,994,204	38,857,480
Energy Related Derivative [Member] | Basis Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure	1,679,289	1,842,048

XML

DERIVATIVE FINANCIAL INSTRUMENTS Fair Value on Balance Sheet (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 16.0	$ 31.0
Derivative Liability, Fair Value, Gross Liability	238.0	107.0
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset		15.0
Derivative Liability, Fair Value, Gross Liability	222.0	87.0
Commodity Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	3.0	1.0
Derivative Liability, Fair Value, Gross Liability	3.0	5.0
Other Energy Management Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	13.0	15.0
Derivative Liability, Fair Value, Gross Liability	13.0	15.0
Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	1.0
Derivative Liability, Fair Value, Gross Liability	42.0	37.0
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	3.0	4.0
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	36.0	28.0
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	2.0	4.0
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	1.0
Derivative Liability, Fair Value, Gross Liability	1.0	1.0
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	15.0	30.0
Derivative Liability, Fair Value, Gross Liability	196.0	69.0
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	1,235.0	1,235.0
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	100.0	33.0
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset		5.0
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	83.0	22.0
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset		10.0
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	2.0	1.0
Derivative Liability, Fair Value, Gross Liability		2.0
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	9.0	9.0
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	4.0	3.0
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	3.0	3.0
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	9.0	11.0
Derivative Liability, Fair Value, Gross Liability	1.0
SCEG | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset		15.0
Derivative Liability, Fair Value, Gross Liability	196.0	65.0
SCEG | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	13.0	10.0
SCEG | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	1.0	1.0
SCEG | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	12.0	9.0
SCEG | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset		15.0
Derivative Liability, Fair Value, Gross Liability	183.0	55.0
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	1,235.0	1,235.0
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	100.0	33.0
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset		5.0
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	83.0	22.0
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset		10.0
Cash Flow Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	120.0	120.0
Cash Flow Hedging [Member] | SCEG | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	$ 36.4	$ 36.4

XML

DERIVATIVE FINANCIAL INSTRUMENTS On Income Statement (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Derivative [Line Items]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	$ (5.0)	$ (3.0)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	$ (7.0)	$ (9.0)
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant	insignificant
Commodity Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 5.0	$ 7.0
Commodity Contract | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	(2.0)	(1.0)
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	2.0	2.0
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)	(2.0)
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	(144.0)	(94.0)
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	(3.0)	(2.0)
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	0.0	4.0
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	1.1
Gas Purchased for Resale [Member] [Member] | Commodity Contract | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(5.0)	(7.0)
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	(2.0)	(2.0)
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	0.7
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	(1.0)	$ 0.0
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	$ 2.1
SCEG
Derivative [Line Items]
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	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	$ (144.0)	$ (94.0)
SCEG | 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	(3.0)	(2.0)
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	0.0	4.0
SCEG | 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	0.7
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	(1.0)	$ 0.0
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	$ 2.1

XML

DERIVATIVE FINANCIAL INSTRUMENTS Derivative Financial Instruments (Credit Risk) (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
LetterofCreditAvailableCommodityDerivativesassetposition	$ 3.0	$ 3.0
Derivative, Net Asset Position, Aggregate Fair Value	13.0	14.0
Collateral Already Posted, Aggregate Fair Value	124.1	50.4
Additional Collateral, Aggregate Fair Value	110.0	44.8
Derivative, Net Liability Position, Aggregate Fair Value	234.1	95.2
Cash collateral to request from interest rate derivative counterparty	0.0	7.3
Interest Rate Derivative, net asset position, Aggregate Fair Value	0.0	7.3
SCEG
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	88.2	13.4
Additional Collateral, Aggregate Fair Value	107.9	43.6
Derivative, Net Liability Position, Aggregate Fair Value	196.1	57.0
Cash collateral to request from interest rate derivative counterparty	0.0	7.3
Interest Rate Derivative, net asset position, Aggregate Fair Value	$ 0.0	$ 7.3

XML

DERIVATIVE FINANCIAL INSTRUMENTS Derivative Financial Instruments Offsetting Assets and Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 16	$ 31
Derivative Asset, Fair Value, Gross Liability	(1)	(1)
Derivative Asset	15	30
Derivative Liability, Fair Value, Gross Liability	238	107
Derivative Liability, Fair Value, Gross Asset	(1)	(1)
Derivative Liability	237	106
Derivative, Collateral, Right to Reclaim Securities	0	(8)
Derivative, Collateral, Right to Reclaim Cash	(124)	(50)
Derivative Liability, Fair Value, Amount Offset Against Collateral	113	48
Derivative, Collateral, Obligation to Return Securities	0	(8)
Derivative, Collateral, Obligation to Return Cash	0	0
Derivative Asset, Fair Value, Amount Offset Against Collateral	15	22
Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	4	8
Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset	11	22
Derivative Liability	2	3
Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	113	50
Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability	122	53
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset		15
Derivative Asset		15
Derivative Liability, Fair Value, Gross Liability	222	87
Derivative Liability	222	87
Derivative, Collateral, Right to Reclaim Securities		(8)
Derivative, Collateral, Right to Reclaim Cash	(116)	(36)
Derivative Liability, Fair Value, Amount Offset Against Collateral	106	43
Derivative, Collateral, Obligation to Return Securities		(8)
Derivative Asset, Fair Value, Amount Offset Against Collateral		7
Commodity Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	3	1
Derivative Asset, Fair Value, Gross Liability	(1)
Derivative Asset	2	1
Derivative Liability, Fair Value, Gross Liability	3	5
Derivative Liability, Fair Value, Gross Asset	(1)
Derivative Liability	2	5
Derivative, Collateral, Right to Reclaim Cash	(2)	(5)
Derivative Liability, Fair Value, Amount Offset Against Collateral	0	0
Derivative Asset, Fair Value, Amount Offset Against Collateral	2	1
Other Energy Management Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	13	15
Derivative Asset, Fair Value, Gross Liability		(1)
Derivative Asset	13	14
Derivative Liability, Fair Value, Gross Liability	13	15
Derivative Liability, Fair Value, Gross Asset		(1)
Derivative Liability	13	14
Derivative, Collateral, Right to Reclaim Cash	(6)	(9)
Derivative Liability, Fair Value, Amount Offset Against Collateral	7	5
Derivative Asset, Fair Value, Amount Offset Against Collateral	13	14
SCEG
Derivative [Line Items]
Derivative Asset		15
Derivative Liability	196	65
SCEG | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset		5
SCEG | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset		10
SCEG | Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	101	34
SCEG | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability	95	31
SCEG | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset		15
Derivative Asset		15
Derivative Liability, Fair Value, Gross Liability	196	65
Derivative Liability	196	65
Derivative, Collateral, Right to Reclaim Securities		(8)
Derivative, Collateral, Right to Reclaim Cash	(88)	(13)
Derivative Liability, Fair Value, Amount Offset Against Collateral	$ 108	44
Derivative, Collateral, Obligation to Return Securities		(8)
Derivative Asset, Fair Value, Amount Offset Against Collateral		$ 7

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	$ 15	$ 30
Derivative Liability	237	106
Available-for-sale Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	$ 11	11
Available-for-sale Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset
Held-to-maturity Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	$ 7
Interest Rate Contract
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		15
Derivative Liability	$ 222	$ 87
Interest Rate Contract | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset
Derivative Liability
Interest Rate Contract | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		$ 15
Derivative Liability	$ 222	87
Commodity Contract
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	2	1
Derivative Liability	2	5
Commodity Contract | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	$ 2	1
Derivative Liability		$ 1
Commodity Contract | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset
Derivative Liability	$ 2	$ 4
Other energy management contracts [Member] [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	13	14
Derivative Liability	$ 13	$ 14
Other energy management contracts [Member] [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset
Derivative Liability	$ 1	$ 4
Other energy management contracts [Member] [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	13	14
Derivative Liability	13	12
SCEG
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		15
Derivative Liability	196	65
SCEG | Interest Rate Contract
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		15
Derivative Liability	196	65
SCEG | Interest Rate Contract | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		15
Derivative Liability	$ 196	$ 65

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details 2) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	$ 5,995.4	$ 5,997.6
Long-term Debt, Fair Value	6,704.5	6,445.7
SCEG
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	4,766.9	4,769.0
Long-term Debt, Fair Value	$ 5,368.3	$ 5,129.1

XML

EMPLOYEE BENEFIT PLANS (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Pension and Other Postretirement Benefit Plans
Pension Contributions	No
Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	$ 5.5	$ 5.8
Interest cost	9.9	9.5
Expected return on assets	(14.1)	(15.5)
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	1.0	1.0
Defined Benefit Plan, Actuarial Net (Gains) Losses	3.7	3.5
Defined Benefit Plan, Net Periodic Benefit Cost	6.0	4.3
Other Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	1.3	1.4
Interest cost	3.0	2.9
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
Defined Benefit Plan, Actuarial Net (Gains) Losses	0.1	0.6
Defined Benefit Plan, Net Periodic Benefit Cost	$ 4.5	5.0
SCEG
Pension and Other Postretirement Benefit Plans
Pension Contributions	No
SCEG | Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	$ 4.5	4.6
Interest cost	8.4	8.0
Expected return on assets	(11.9)	(13.0)
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	0.8	0.8
Defined Benefit Plan, Actuarial Net (Gains) Losses	3.1	3.0
Defined Benefit Plan, Net Periodic Benefit Cost	4.9	3.4
SCEG | Other Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	1.0	1.1
Interest cost	2.5	2.3
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
Defined Benefit Plan, Actuarial Net (Gains) Losses	0.1	0.4
Defined Benefit Plan, Net Periodic Benefit Cost	$ 3.7	$ 3.9

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COMMITMENTS AND CONTINGENCIES (Details) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Nuclear Generation
Goal For Reduced Carbon Dioxide Emissions From 2005 Levels By 2030 Under Clean Air Act	32.00%
NPDES permit renewal permit period	five
Regulatory Assets, Noncurrent	$ 2,068.0	$ 1,937.0
Forecasted Incremental Capital Costs Associated With Schedule Delays, 2015 Petition	539.0
EPC Contract Amendment, New Nuclear Construction Completion Bonus	151.0
EPC Contract Amendment, Increase In Fixed Component Of Contract Price, Payments	62.5
EPC Contract Amendment, Revised Construction Milestone Payment Schedule, Payments	300.0
EPC Contract Amendment, Payment and Performance Bonds	$ 45.0
EPC Contract Amendment, Payment And Performance Bonds, Percentage of Billing	0.00%
EPC Contract Amendment, Payment And Performance Bonds, Maximum Aggregate Nominal Coverage	$ 100.0
EPC Contract Amendment, Additional Sales Tax on Fixed Price Option	10.0
EPC Contract Amendment, Fixed Price Option, Increase In Total New Nuclear Project Cost	774.0
SCEG
Commitments and contingencies
Federal Limit on Public Liability Claims from Nuclear Incident Approximate	13,400.0
Maximum Insurance Coverage For Each Nuclear Plant by ANI	375.0
Environmental Remediation Costs Recognized in Regulatory Assets	34.4
Nuclear Insurance
Maximum liability assessment per reactor for each nuclear incident	127.3
Maximum Federal Limit on Public Liability Claims Per Reactor for Each Year	18.9
Maximum Federal Limit on Public Liability Claims per Reactor for each Nuclear Incident at 2/3	84.8
Maximum Federal Limit on Public Liability Claims Per Incident for Each Year	$ 12.6
Inflation adjustment period for nuclear insurance	5
Maximum loss for a single nuclear incident	$ 2,750.0
NEIL Maximum Insurance Coverage of Accidental Property Damage	500.0
NEIL Maximum Insurance Coverage To Nuclear Facility For Property Damage And Outage Costs From Non-Nuclear Event	2,250.0
EMANI Maximum Retrospective Premium Assessment	1.8
EMANI Maximum Insurance Coverage for Summer Station Unit 1 For Property Damage And Outage Costs From Non-Nuclear Event	415.0
NEIL Maximum Prosepective Insurance Premium Per Nuclear Incident	43.5
NEIL Maximum Insurance Coverage to Nuclear Facility for Property Damage and Outage Costs	$ 2,750.0
Environmental
Number of MGP decommissioned sites that contain residues of byproduct chemicals	4
Site Contingency MGP Estimated Environmental Remediation Costs	$ 18.4
Nuclear Generation
Number Of States Required To Reduce Emissions Under CSAPR	28
Regulatory Assets, Noncurrent	$ 1,986.0	$ 1,857.0
Public Utilities, Authorized Allowable Return on Common Equity, Percentage	10.50%	0.00%
EPC Contract Amendment, Increase In Fixed Component Of Contract Price	$ 165.0
EPC Contract Amendment, Credit Applied To Target Component Of New Units Contract Price	27.0
EPC Contract Amendment, Cap On Delay Oriented Liquidated Damages Per New Nuclear Unit	255.0
EPC Contract Amendment, Revised Construction Milestone Payment Schedule, Per Month	55.0
EPC Contract Amendment, Increase In Total New Nuclear Project Cost	286.0
Total New Nuclear Project Cost Approved By SCPSC In September 2015	6,800.0
EPC Contract Amendment, New Nuclear Project Costs, Estimated Change Orders as of April 30, 2016	53.0
EPC Contract Amendment, Total New Nuclear Project Cost Including Amendment Increase	7,200.0
EPC Contract Amendment, Increase In Fixed Component Of Contract Price, Payments	34.4
EPC Contract Amendment, Revised Construction Milestone Payment Schedule, Payments	165.0
EPC Contract Amendment, Payment and Performance Bonds	25.0
EPC Contract Amendment, Payment And Performance Bonds, Maximum Aggregate Nominal Coverage	55.0
EPC Contract Amendment, Fixed Price Option, Project Cost Including Fixed Option Price Increase	7,700.0
EPC Contract Amendment, Fixed Price Option, Price For New Nuclear Construction After June 2015	3,000.0
EPC Contract Amendment, Fixed Price Option, Cap On Delay Oriented Liquidated Damages Per New Nuclear Unit	186.0
EPC Contract Amendment, Fixed Price Option, New Nuclear Construction Completion Bonus	83.0
Summer Station New Units and Transmission Assets [Domain]
Nuclear Generation
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	$ 3,800.0
SCEG
Nuclear Insurance
Jointly Owned Utility Plant, Proportionate Ownership Share	5.00%
Summer Station New Units [Domain]
Nuclear Insurance
Jointly Owned Utility Plant, Proportionate Ownership Share	55.00%
Nuclear Generation
jointly owned utility plant ownership, construction financing cost	$ 3,200.0
EPC Contract Amendment, Increase In Fixed Component Of Contract Price	300.0
EPC Contract Amendment, Credit Applied To Target Component Of New Units Contract Price	50.0
EPC Contract Amendment, Cap On Delay Oriented Liquidated Damages Per New Nuclear Unit	463.0
EPC Contract Amendment, New Nuclear Construction Completion Bonus	275.0
EPC Contract Amendment, Revised Construction Milestone Payment Schedule, Per Month	100.0
Nuclear Production Tax Credits	$ 1,400.0
Nuclear Production Tax Credit realization period	8
EPC Contract Amendment, Fixed Price Option, Price For New Nuclear Construction After June 2015	$ 6,000.0
EPC Contract Amendment, Fixed Price Option, Cap On Delay Oriented Liquidated Damages Per New Nuclear Unit	338.0
EPC Contract Amendment, Fixed Price Option, New Nuclear Construction Completion Bonus	150.0
Capital costs, owners [Domain]
Nuclear Generation
Forecasted incremental capital costs, 2015 petition	245.0
Forecasted Total Capital Costs, 2015 Petition	5,200.0
Capital costs, Other [Domain] [Domain]
Nuclear Generation
Forecasted incremental capital costs, 2015 petition	453.0
Forecasted Total Capital Costs, 2015 Petition	6,800.0
Scenario, Forecast [Member] | SCEG
Nuclear Generation
Additional ownership in new units			2.00%	2.00%	1.00%
Minimum [Member] | SCEG
Nuclear Generation
Additional ownership in new units, dollars	750.0
Maximum [Member] | SCEG
Nuclear Generation
Additional ownership in new units, dollars	$ 850.0

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SEGMENT OF BUSINESS INFORMATION (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Segment Reporting Information [Line Items]
Gain (Loss) On Disposition Of Regulated Business Net Of Transaction Costs	$ 0	$ 235
Gain (Loss) on Disposition of Nonregulated Business, Net of Transaction Costs		202
Electric Domestic Regulated Revenue	592	629
Revenues	0	0
Net Income (Loss) Available to Common Stockholders, Basic	176	400
Operating Income	(331)	(586)
Regulated Operating Revenue, Gas	299	369
Regulated and Unregulated Operating Revenue	1,172	1,389
Segment Assets	17,368		$ 17,146
Electric Operations
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue	592	629
Revenues	1	0
Operating Income	(198)	(199)
Segment Assets	11,039		10,883
Gas Distribution
Segment Reporting Information [Line Items]
Revenues	1	0
Operating Income	(94)	(96)
Regulated and Unregulated Operating Revenue	299	368
Segment Assets	2,676		2,606
Retail Gas Marketing
Segment Reporting Information [Line Items]
Revenues	0	0
Net Income (Loss) Available to Common Stockholders, Basic	22	27
Regulated and Unregulated Operating Revenue	171	204
Segment Assets	140		106
Energy Marketing [Member]
Segment Reporting Information [Line Items]
Revenues	22	35
Net Income (Loss) Available to Common Stockholders, Basic	2	6
Regulated and Unregulated Operating Revenue	110	187
Segment Assets	84		95
All Other [member]
Segment Reporting Information [Line Items]
Revenues	98	114
Net Income (Loss) Available to Common Stockholders, Basic	0	207
Operating Income	0	(238)
Regulated and Unregulated Operating Revenue	0	4
Segment Assets	994		998
Adjustments/Eliminations
Segment Reporting Information [Line Items]
Revenues	(122)	(149)
Net Income (Loss) Available to Common Stockholders, Basic	152	160
Operating Income	39	(53)
Regulated and Unregulated Operating Revenue	0	(3)
Segment Assets	2,435		2,458
SCEG
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue	593	630
Operating Income	(236)	(237)
Regulated Operating Revenue, Gas	124	142
Net Income (Loss) Attributable to Parent	113	122
Segment Assets	14,932		14,765
Regulated Operating Revenue	717	772
SCEG | Electric Operations
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue	593	630
Operating Income	(198)	(199)
Segment Assets	11,039		10,883
SCEG | Gas Distribution
Segment Reporting Information [Line Items]
Operating Income	(38)	(38)
Regulated and Unregulated Operating Revenue	124	142
Segment Assets	768		757
SCEG | Adjustments/Eliminations
Segment Reporting Information [Line Items]
Operating Income	0	0
Regulated and Unregulated Operating Revenue	0	0
Net Income (Loss) Attributable to Parent	113	$ 122
Segment Assets	$ 3,125		$ 3,125

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AFFILIATED TRANSACTIONS -SCEG (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$ 75.6	$ 73.1
Canadys Refined Coal [Member]
Related Party Transaction [Line Items]
Equity Method Investment, Ownership Percentage	40.00%
Related Party Transaction, Purchases from Related Party	$ 52.8	70.1
Sales to Affiliate	52.5	69.7
Related Party Tax Expense, Due from Affiliates, Current	15.2	12.8
Related Party Tax Expense, Due to Affiliates, Current	15.3	12.9
Carolina Gas Transmission [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party			$ 3.4
Energy Marketing [Member]
Related Party Transaction [Line Items]
Due to Affiliate, Current	4.0		7.5
Cost of Natural Gas Purchases	22.4	$ 34.6
SCEG
Related Party Transaction [Line Items]
Due to Affiliate, Current	116.0		113.0
Due from Affiliate, Current	15.0		22.0
Accounts Payable, Related Parties, Current	$ 48.1		$ 57.0