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 September 30, 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 October 31, 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			43
	SCANA Corporation		43
	South Carolina Electric & Gas Company		50
Item 3. Quantitative and Qualitative Disclosures About Market Risk			55
Item 4. Controls and Procedures			56
PART II. OTHER INFORMATION
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			57
Item 5. Other Information			57
Item 6. Exhibits			57
Signatures			58
Exhibit Index			59

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 (Loss)
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
DRB	Dispute Review Board, provided for under the October 2015 Amendment
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
Fluor	Fluor Corporation
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
IRC	Internal Revenue Code of 1986, as amended
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

4

LOC	Lines of Credit
MATS	Mercury and Air Toxics Standards
MGP	Manufactured Gas Plant
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
Registrants	SCANA and SCE&G
Retail Gas Marketing	SCANA Energy
ROE	Return on Equity
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.     FINANCIAL STATEMENTS

SCANA Corporation and Subsidiaries

Condensed Consolidated Balance Sheets

(Unaudited) 

Millions of dollars	September 30, 2016			December 31, 2015
Assets
Utility Plant In Service	$	13,307		$	12,883
Accumulated Depreciation and Amortization	(4,413		)	(4,307		)
Construction Work in Progress	4,584			4,051
Nuclear Fuel, Net of Accumulated Amortization	312			308
Goodwill, net of writedown of $230	210			210
Utility Plant, Net	14,000			13,145
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation of $136 and $124	277			280
Assets held in trust, net-nuclear decommissioning	125			115
Other investments	74			71
Nonutility Property and Investments, Net	476			466
Current Assets:
Cash and cash equivalents	56			176
Receivables:
Customer, net of allowance for uncollectible accounts of $5 and $5	530			505
Income taxes	306			—
Other	96			227
Inventories (at average cost):
Fuel and gas supply	134			164
Materials and supplies	152			148
Prepayments	113			115
Other current assets	66			43
Total Current Assets	1,453			1,378
Deferred Debits and Other Assets:
Regulatory assets	2,202			1,937
Other	315			220
Total Deferred Debits and Other Assets	2,517			2,157
Total	$	18,446		$	17,146

See Combined Notes to Condensed Consolidated Financial Statements.

6

Millions of dollars	September 30, 2016			December 31, 2015
Capitalization and Liabilities
Common Stock - no par value, 142.9 million shares outstanding	$	2,390		$	2,390
Retained Earnings	3,342			3,118
Accumulated Other Comprehensive Loss	(57		)	(65		)
Total Common Equity	5,675			5,443
Long-Term Debt, net	6,472			5,882
Total Capitalization	12,147			11,325
Current Liabilities:
Short-term borrowings	778			531
Current portion of long-term debt	117			116
Accounts payable	278			590
Customer deposits and customer prepayments	179			137
Taxes accrued	158			242
Interest accrued	92			83
Dividends declared	80			76
Derivative financial instruments	54			50
Other	128			127
Total Current Liabilities	1,864			1,952
Deferred Credits and Other Liabilities:
Deferred income taxes, net	2,063			1,907
Asset retirement obligations	543			520
Pension and other postretirement benefits	327			315
Unrecognized tax benefits	254			44
Regulatory liabilities	864			855
Other	384			228
Total Deferred Credits and Other Liabilities	4,435			3,869
Commitments and Contingencies (Note 9)
Total	$	18,446		$	17,146

See Combined Notes to Condensed Consolidated Financial Statements.

7

SCANA Corporation and Subsidiaries

Condensed Consolidated Statements of Income

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Millions of dollars, except per share amounts	2016			2015			2016			2015
Operating Revenues:
Electric	$	817		$	742		$	2,035		$	2,008
Gas - regulated	111			112			538			610
Gas - nonregulated	165			214			598			805
Total Operating Revenues	1,093			1,068			3,171			3,423
Operating Expenses:
Fuel used in electric generation	176			187			443			525
Purchased power	21			14			50			38
Gas purchased for resale	202			260			752			1,030
Other operation and maintenance	187			182			558			527
Depreciation and amortization	93			75			276			267
Other taxes	66			58			192			176
Total Operating Expenses	745			776			2,271			2,563
Gain on sale of CGT, net of transaction costs	—			—			—			235
Operating Income	348			292			900			1,095
Other Income (Expense):
Other income	15			19			46			56
Other expense	(7		)	(16		)	(31		)	(44		)
Gain on sale of SCI, net of transaction costs	—			—			—			107
Interest charges, net of allowance for borrowed funds used during construction of $5, $5, $14, and $12	(88		)	(81		)	(255		)	(236		)
Allowance for equity funds used during construction	7			8			22			20
Total Other Expense	(73		)	(70		)	(218		)	(97		)
Income Before Income Tax Expense	275			222			682			998
Income Tax Expense	86			73			211			350
Net Income	$	189		$	149		$	471		$	648
Earnings Per Share of Common Stock	$	1.32		$	1.04		$	3.29		$	4.53
Weighted Average Common Shares Outstanding (millions)	142.9			142.9			142.9			142.9
Dividends Declared Per Share of Common Stock	$	0.575		$	0.545		$	1.725		$	1.635

See Combined Notes to Condensed Consolidated Financial Statements.

8

SCANA Corporation and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income

(Unaudited) 

	Three Months Ended September 30,						Nine Months Ended September 30,
Millions of dollars	2016			2015			2016			2015
Net Income	$	189		$	149		$	471		$	648
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 $-, $(4), $(3), and $(5)	(1		)	(7		)	(4		)	(8		)
Cash flow hedging activities reclassified to interest expense, net of tax of $1, $1, $3, and $3	2			2			6			6
Cash flow hedging activities reclassified to gas purchased for resale, net of tax of $-, $-, $3, and $6	—			1			6			10
Net unrealized gains (losses) on cash flow hedging activities	1			(4		)	8			8
Deferred cost of employee benefit plans, net of tax of $-, $-, $-, and $(2)	—			1			—			(3		)
Other Comprehensive Income (Loss)	1			(3		)	8			5
Total Comprehensive Income	$	190		$	146		$	479		$	653

See Combined Notes to Condensed Consolidated Financial Statements.

9

SCANA Corporation and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(Unaudited) 

	Nine Months Ended September 30,
Millions of dollars	2016			2015
Cash Flows From Operating Activities:
Net income	$	471		$	648
Adjustments to reconcile net income to net cash provided from operating activities:
Gain on sale of subsidiaries	—			(355		)
Deferred income taxes, net	151			(98		)
Depreciation and amortization	289			276
Amortization of nuclear fuel	42			41
Allowance for equity funds used during construction	(22		)	(20		)
Carrying cost recovery	(12		)	(9		)
Changes in certain assets and liabilities:				—
Receivables	(8		)	192
Income taxes receivable	(306		)	—
Inventories	(21		)	2
Prepayments	(2		)	196
Regulatory assets	(14		)	26
Regulatory liabilities	2			14
Accounts payable	(36		)	(85		)
Unrecognized tax benefits	210			2
Taxes accrued	(84		)	2
Derivative financial instruments	(9		)	(8		)
Other assets	(58		)	81
Other liabilities	86			(98		)
Net Cash Provided From Operating Activities	679			807
Cash Flows From Investing Activities:
Property additions and construction expenditures	(1,178		)	(851		)
Proceeds from sale of subsidiaries	—			647
Proceeds from investments (including derivative collateral returned)	629			872
Purchase of investments (including derivative collateral posted)	(743		)	(872		)
Payments upon interest rate derivative contract settlements	(88		)	(152		)
Proceeds upon interest rate derivative contract settlements	—			10
Net Cash Used For Investing Activities	(1,380		)	(346		)
Cash Flows From Financing Activities:
Proceeds from issuance of common stock	—			14
Proceeds from issuance of long-term debt	592			491
Repayment of long-term debt	(15		)	(164		)
Dividends	(243		)	(231		)
Short-term borrowings, net	247			(654		)
Net Cash Provided From (Used For) Financing Activities	581			(544		)
Net Decrease In Cash and Cash Equivalents	(120		)	(83		)
Cash and Cash Equivalents, January 1	176			137
Cash and Cash Equivalents, September 30	$	56		$	54
Supplemental Cash Flow Information:
Cash paid for– Interest (net of capitalized interest of $14 and $12)	$	235		$	224
– Income taxes	229			184
Noncash Investing and Financing Activities:
Accrued construction expenditures	80			85
Capital leases	12			5

 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 Amount			Retained Earnings			Gains (Losses) from 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							471												471
Other Comprehensive Income (Loss)
Losses arising during the period										(4		)	—			(4		)	(4		)
Losses/amortization reclassified from AOCI										12			—			12			12
Total Comprehensive Income							471			8			—			8			479
Dividends Declared							(247		)										(247		)
Balance as of September 30, 2016	143	$	2,402	$	(12	)	$	3,342		$	(45	)	$	(12	)	$	(57	)	$	5,675
Balance as of January 1, 2015	143	$	2,388	$	(10	)	$	2,684		$	(63	)	$	(12	)	$	(75	)	$	4,987
Net Income							648												648
Other Comprehensive Income (Loss)
Losses arising during the period										(8		)	(3		)	(11		)	(11		)
Losses/amortization reclassified from AOCI										16			—			16			16
Total Comprehensive Income (Loss)							648			8			(3		)	5			653
Issuance of Common Stock	—	14		(1		)													13
Dividends Declared							(234		)										(234		)
Balance as of September 30, 2015	143	$	2,402	$	(11	)	$	3,098		$	(55	)	$	(15	)	$	(70	)	$	5,419

Dividends declared per share of common stock were $1.725 and $1.635 for September 30, 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	September 30, 2016			December 31, 2015
Assets
Utility Plant In Service	$	11,420		$	11,153
Accumulated Depreciation and Amortization	(3,961		)	(3,869		)
Construction Work in Progress	4,538			3,997
Nuclear Fuel, Net of Accumulated Amortization	312			308
Utility Plant, Net ($695 and $700 related to VIEs)	12,309			11,589
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	68			68
Assets held in trust, net-nuclear decommissioning	125			115
Other investments	3			1
Nonutility Property and Investments, Net	196			184
Current Assets:
Cash and cash equivalents	29			130
Receivables:
Customer, net of allowance for uncollectible accounts of $4 and $3	402			324
Affiliated companies	4			22
Income taxes	206			—
Other	80			202
Inventories (at average cost):
Fuel	77			98
Materials and supplies	139			136
Prepayments	99			92
Other current assets	48			15
Total Current Assets ($57 and $88 related to VIEs)	1,084			1,019
Deferred Debits and Other Assets:
Regulatory assets	2,114			1,857
Other	275			116
Total Deferred Debits and Other Assets ($64 and $53 related to VIEs)	2,389			1,973
Total	$	15,978		$	14,765

See Combined Notes to Condensed Consolidated Financial Statements.

12

Millions of dollars	September 30, 2016			December 31, 2015
Capitalization and Liabilities
Common Stock - no par value, 40.3 million shares outstanding	$	2,860		$	2,760
Retained Earnings	2,469			2,265
Accumulated Other Comprehensive Loss	(3		)	(3		)
Total Common Equity	5,326			5,022
Noncontrolling Interest	133			129
Total Equity	5,459			5,151
Long-Term Debt, net	5,153			4,659
Total Capitalization	10,612			9,810
Current Liabilities:
Short-term borrowings	714			420
Current portion of long-term debt	112			110
Accounts payable	183			469
Affiliated payables	95			113
Customer deposits and customer prepayments	131			93
Taxes accrued	148			299
Interest accrued	72			66
Dividends declared	76			75
Derivative financial instruments	48			34
Other	62			61
Total Current Liabilities	1,641			1,740
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,859			1,732
Asset retirement obligations	510			488
Pension and other postretirement benefits	193			186
Unrecognized tax benefits	254			44
Regulatory liabilities	630			635
Other	262			113
Other affiliate	17			17
Total Deferred Credits and Other Liabilities	3,725			3,215
Commitments and Contingencies (Note 9)
Total	$	15,978		$	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						Nine Months Ended
	September 30,						September 30,
Millions of dollars	2016			2015			2016			2015
Operating Revenues:
Electric	$	818		$	743		$	2,039		$	2,013
Gas	64			63			253			275
Total Operating Revenues	882			806			2,292			2,288
Operating Expenses:
Fuel used in electric generation	176			187			443			525
Purchased power	21			14			50			38
Gas purchased for resale	36			37			126			151
Other operation and maintenance	152			148			454			428
Depreciation and amortization	76			59			225			220
Other taxes	62			54			178			163
Total Operating Expenses	523			499			1,476			1,525
Operating Income	359			307			816			763
Other Income (Expense):
Other income	7			6			20			24
Other expense	(4		)	(7		)	(19		)	(21		)
Interest charges, net of allowance for borrowed funds used during construction of $5, $4, $13, and $11	(70		)	(63		)	(201		)	(183		)
Allowance for equity funds used during construction	6			8			19			18
Total Other Expense	(61		)	(56		)	(181		)	(162		)
Income Before Income Tax Expense	298			251			635			601
Income Tax Expense	94			84			202			196
Net Income	204			167			433			405
Net Income Attributable to Noncontrolling Interest	(3		)	(3		)	(10		)	(11		)
Earnings Available to Common Shareholder	$	201		$	164		$	423		$	394
Dividends Declared on Common Stock	$	76		$	71		$	225		$	211

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 September 30,						Nine Months Ended September 30,
Millions of dollars	2016			2015			2016			2015
Net Income and Total Comprehensive Income	$	204		$	167		$	433		$	405
Comprehensive income attributable to noncontrolling interest	(3		)	(3		)	(10		)	(11		)
Comprehensive income available to common shareholder	$	201		$	164		$	423		$	394

See Combined Notes to Condensed Consolidated Financial Statements.

14

South Carolina Electric & Gas Company and Affiliates

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	Nine Months Ended September 30,
Millions of dollars	2016			2015
Cash Flows From Operating Activities:
Net income	$	433		$	405
Adjustments to reconcile net income to net cash provided from operating activities:
Deferred income taxes, net	127			(14		)
Depreciation and amortization	229			221
Amortization of nuclear fuel	42			41
Allowance for equity funds used during construction	(19		)	(18		)
Carrying cost recovery	(12		)	(9		)
Changes in certain assets and liabilities:
Receivables	(70		)	(41		)
Receivables - affiliate	9			87
Income tax receivable	(206		)	—
Inventories	(14		)	(15		)
Prepayments	(15		)	63
Regulatory assets	(6		)	24
Regulatory liabilities	(3		)	11
Accounts payable	(13		)	34
Accounts payable - affiliate	(13		)	(55		)
Taxes accrued	(151		)	109
Unrecognized tax benefit	210			2
Other assets	(117		)	67
Other liabilities	64			(110		)
Net Cash Provided From Operating Activities	475			802
Cash Flows From Investing Activities:
Property additions and construction expenditures	(1,024		)	(748		)
Proceeds from investments (including derivative collateral returned)	577			768
Purchase of investments (including derivative collateral posted)	(699		)	(776		)
Payments upon interest rate derivative contract settlements	(88		)	(152		)
Proceeds upon interest rate derivative contract settlements	—			10
Proceeds from money pool investments	9			80
Net Cash Used For Investing Activities	(1,225		)	(818		)
Cash Flows From Financing Activities:
Proceeds from issuance of long-term debt	494			491
Repayment of long-term debt	(10		)	(10		)
Dividends	(224		)	(214		)
Contributions from parent	100			200
Return of capital to parent	—			(4		)
Money pool borrowings, net	(5		)	(42		)
Short-term borrowings, net	294			(475		)
Net Cash Provided From Financing Activities	649			(54		)
Net Decrease In Cash and Cash Equivalents	(101		)	(70		)
Cash and Cash Equivalents, January 1	130			100
Cash and Cash Equivalents, September 30	$	29		$	30
Supplemental Cash Flow Information:
Cash paid for – Interest (net of capitalized interest of $13 and $11)	$	182		$	169
– Income taxes paid	286			89
– Income taxes received	9			84
Noncash Investing and Financing Activities:
Accrued construction expenditures	71			76
Capital leases	12			5

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
Millions	Shares	Amount		Retained Earnings			AOCI			Noncontrolling Interest			Total Equity
Balance at January 1, 2016	40	$	2,760	$	2,265		$	(3	)	$	129		$	5,151
Earnings available to common shareholder				423						10			433
Total Comprehensive Income				423			—			10			433
Capital contributions from parent		100											100
Cash dividend declared				(219		)				(6		)	(225		)
Balance at September 30, 2016	40	$	2,860	$	2,469		$	(3	)	$	133		$	5,459
Balance at January 1, 2015	40	$	2,560	$	2,077		$	(3	)	$	123		$	4,757
Earnings available to common shareholder				394						11			405
Total Comprehensive Income				394			—			11			405
Capital contributions from parent		196											196
Cash dividend declared				(205		)				(5		)	(210		)
Balance at September 30, 2015	40	$	2,756	$	2,266		$	(3	)	$	129		$	5,148

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 $483 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 4.

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, through an agency relationship, 41% and 46% of PSNC Energy’s natural gas inventory at September 30, 2016 and December 31, 2015, respectively, with a carrying value of $13.1 million and $17.7 million, respectively.  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. When applicable, 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.

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, $(100) million of non-cash changes in fair value of interest rate swaps has been reclassified from the changes in Derivative financial instruments caption (which for Consolidated SCE&G resulted in the caption being eliminated) with offsetting reclassifications of $66 million from the changes in Regulatory assets caption, $(5) million from the changes in Regulatory liabilities caption, $(6) million from the changes in Other assets caption and $45 million from the changes in Other liabilities caption. 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, and the caption of Losses from equity method investments has been eliminated and its amount included within changes in Other assets. 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 earlier revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive

in exchange for those goods or services. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018. The guidance permits adoption using a retrospective method, with options to elect certain practical expedients, or recognition of a cumulative effect in the year of initial adoption. The Company and Consolidated SCE&G have not determined which method of adoption will be employed or what practical expedients may be elected. The Company and Consolidated SCE&G have not determined the impact this guidance will have on their respective financial statements. However, the identification of implementation project team members and the analysis of contracts with customers to which the guidance might be applicable, particularly large customer contracts, have begun.

In 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 and have determined that the adoption of this guidance will not have a significant impact on their respective financial statements.

In January 2016, the FASB issued accounting guidance that will change how entities measure certain equity investments and financial liabilities, among other things. The Company and Consolidated SCE&G expect to adopt this

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guidance when required in the first quarter of 2018. The Company and Consolidated SCE&G are evaluating this guidance and do not anticipate that its adoption will have a significant impact on their respective financial statements.

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

leases. The guidance applies a right-of-use model and, for lessees, requires all leases with a duration over 12 months to be

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

and without consideration of any regulatory accounting requirements which may apply, depending primarily on the nature of the assets and the relative consumption of them, lease costs will be recognized either through the separate amortization of the right-of-use asset and the recognition of the interest cost related to the payment obligation, or through the recording of a combined straight-line rental expense. For lessors, the guidance calls for the recognition of income either through the derecognition of assets and subsequent recording of interest income on lease amounts receivable, or through the recognition of rental income on a straight-line basis, also depending on the nature of the assets and relative consumption. The guidance will be effective for years beginning in 2019. The Company and Consolidated SCE&G have not determined what impact this guidance will have on their respective financial statements. However, the identification of implementation project team members and the initial identification and analysis of leasing and related contracts to which the guidance might be applicable have begun.

In 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, based on the nature of their current share-based awards practices, do not anticipate that its adoption will have a significant impact on their respective financial statements.

In June 2016, the FASB issued accounting guidance requiring the use of a current expected credit loss impairment model for certain financial instruments. The new model is applicable to trade receivables and most debt instruments, among other financial instruments, and is intended to result in impairment losses being recognized earlier than under current guidance. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted in 2019. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective financial statements.

In August 2016, the FASB issued accounting guidance to reduce diversity in cash flow classification related to certain transactions. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018 and do not anticipate that its adoption will impact their respective financial statements.

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, ORS and certain other parties concerning SCE&G's petition for approval to participate in a DER program and to recover DER program costs as a separate component of SCE&G's overall fuel factor. Under this order, SCE&G will, among other things, implement programs to encourage the development of renewable energy facilities with a total nameplate capacity of at least approximately 84.5 MW by the end of 2020, of which half is to be customer-scale solar capacity and half is to be utility-scale solar capacity.

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

Electric - Base Rates

Pursuant to an SCPSC order, SCE&G removes from rate base certain deferred income tax assets arising from capital expenditures related to the New Units and accrues carrying costs on those amounts during periods in which they are not included in rate base.  Such carrying costs are determined at SCE&G’s weighted average long-term debt borrowing rate and are recorded as a regulatory asset and other income. Carrying costs during the three and nine months ended September 30, 2016

19

totaled $3.5 million and $10.0 million, respectively. During the three and nine months ended September 30, 2015, carrying costs totaled $2.4 million and $6.5 million, respectively. SCE&G anticipates that when the New Units are placed in service and accelerated tax depreciation is recognized on them, these deferred income tax assets will decline. When these 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 rider. Under the terms of the order, SCE&G may request an annual adjustment to the pension rider. The increased pension rider is designed to allow SCE&G to recover projected pension costs, including under-collections, over a 12-month period, beginning with the first billing cycle in May 2016.

In 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. 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 along with a shared savings incentive associated with the DSM Programs.

Electric - BLRA

On May 26, 2016, SCE&G petitioned the SCPSC seeking approval to update the capital cost schedule and construction milestone schedule for the New Units consistent with the October 2015 Amendment. Within this petition, SCE&G also informed the SCPSC that it had notified WEC of its intent to elect the fixed price option, subject to concurrence by Santee Cooper and approval by the SCPSC. The petition reflects an increase in total project costs of approximately $852 million over the cost approved by the SCPSC in September 2015, of which approximately $505 million is directly attributable to the fixed price option. On July 1, 2016, SCE&G reduced the total project cost amount set forth in its petition to $846 million. SCE&G's estimated gross construction cost for the project is now estimated to be approximately $7.7 billion, including owner’s costs, transmission, escalation and AFC. SCE&G executed the fixed price option on July 1, 2016, for itself and on behalf of Santee Cooper, subject to SCPSC approval.

On September 1, 2016, SCE&G, ORS and certain other parties entered into a settlement agreement related to SCE&G’s May 26, 2016 petition to update construction and capital cost schedules, including SCE&G’s election of the fixed price option included in the October 2015 Amendment. Under the terms of the settlement agreement, the settling parties agree to support SCPSC approval of the updated construction schedule, which indicates substantial completion dates of August 2019 and August 2020 for the New Units, and SCE&G’s election of the fixed price option. In addition, the settling parties agree to the inclusion of an additional $831 million in the capital cost schedule and to revise the allowed ROE for the New Units from 10.50% to 10.25%. The revised ROE will be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2017, until such time as the New Units are completed. Also, pursuant to the settlement agreement, SCE&G agreed not to file any future requests to amend its capital cost schedule prior to January 28, 2019. For those capital costs which were included in the total project amount set forth in SCE&G’s petition but not included in the capital cost schedule as agreed upon by the settling parties, SCE&G may seek to include those costs in its calculation of revised rates after January 2019. The settlement agreement is subject to SCPSC approval. A public hearing on this matter was held in October 2016, and the SCPSC is expected to issue its order in November 2016.  See also Note 9.

On October 19, 2016, the SCPSC approved an increase of approximately $64.4 million, or 2.7%, in SCE&G's retail electric rates under provisions of the BLRA. The rate increase is effective for the first billing cycle on or after November 27, 2016.

Gas - SCE&G

By order dated October 13, 2016, the SCPSC approved SCE&G's quarterly monitoring report for the 12-month period ended March 31, 2016, and an approximately $4.1 million, or 1.2%, overall increase to its natural gas rates under the terms of the RSA. The rate adjustment will be effective for the first billing cycle in November 2016.

SCE&G's natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred, including transportation costs. SCE&G's gas rates are calculated using a methodology which may adjust the cost of gas monthly based on a 12-month rolling average, and its gas purchasing policies and practices are reviewed annually by the SCPSC. SCE&G's annual PGA hearing for the 12-month period ending July 31, 2016, was held on November 3, 2016, and the SCPSC's decision is pending.

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Gas - PSNC Energy

On October 28, 2016, the NCUC granted PSNC Energy a net annual increase of approximately $19.1 million, or 4.39%, in rates and charges to customers, and set PSNC Energy's authorized ROE at 9.7%. The rate increase is largely associated with recovering costs related to expanding and operating PSNC Energy's pipeline system. In addition, PSNC Energy was authorized to implement a tracker that provides for biannual rate adjustments in order to recover the revenue requirement associated with integrity management plant investment and associated costs incurred by PSNC Energy resulting from prevailing federal standards for pipeline integrity and safety that are not otherwise included in current base rates.  The new rates are effective for services rendered on or after November 1, 2016.

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	September 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
Regulatory Assets:
Accumulated deferred income taxes	$	301	$	298	$	294	$	291
Environmental remediation costs	33		42		26		35
AROs and related funding	402		405		380		384
Deferred employee benefit plan costs	311		325		282		295
Deferred losses on interest rate derivatives	791		535		791		535
Unrecovered plant	119		127		119		127
DSM Programs	58		61		58		61
Deferred costs related to uncertain tax position	14		—		14		—
Other	173		144		150		129
Total Regulatory Assets	$	2,202	$	1,937	$	2,114	$	1,857

Regulatory Liabilities:
Asset removal costs	$	756	$	732	$	533	$	519
Deferred gains on interest rate derivatives	80		96		80		96
Other	28		27		17		20
Total Regulatory Liabilities	$	864	$	855	$	630	$	635

Accumulated deferred income tax liabilities that arise from utility operations that have not been included in customer rates are recorded as a regulatory asset.  A substantial portion of these regulatory assets relate to depreciation and are expected to be recovered over the remaining lives of the related property which may range up to approximately 85 years.  Similarly, accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability.

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 18 years.

AROs and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station and conditional AROs related to generation, transmission and distribution properties, including gas pipelines. These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 110 years.

Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under GAAP. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which

21

were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. In 2013 SCE&G began recovering through utility rates approximately $63 million of deferred pension costs for electric operations over approximately 30 years and approximately $14 million of deferred pension costs for gas operations over approximately 14 years. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees, or up to approximately 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. 

Deferred costs related to uncertain tax position primarily represent the estimated amounts of domestic production activities deductions foregone as a result of the Company’s deduction of certain research and experimentation expenditures for income tax purposes, net of related tax credits, as well as accrued interest expense and other costs arising from this unrecognized tax benefit. SCE&G's current customer rates reflect the availability of domestic production activities deductions. These net deferred costs are expected to be recovered through utility rates following ultimate resolution of the claims. See also Note 5.

Various other regulatory assets are expected to be recovered 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 September 30, 2016 and December 31, 2015. Gains and losses on cash flow hedges reclassified from AOCI during the nine months ended September 30, 2016 resulted in higher interest expense of $6 million and higher cost of gas purchased for resale of $6 million. Such reclassifications during the comparable period in 2015 resulted in higher interest expense of $6 million and higher cost of gas purchased for resale of $10 million.

Authorized shares of SCE&G common stock were 50 million as of September 30, 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 September 30, 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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4.     LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

On November 1, 2016, Consolidated SCE&G paid at maturity $100 million related to a nuclear fuel financing which had an imputed interest rate of 0.78%.

In June 2016, SCE&G issued $425 million of 4.1% first mortgage bonds due June 15, 2046. In addition, SCE&G issued $75 million of 4.5% first mortgage bonds due June 1, 2064, which constituted a reopening of $300 million of 4.5% first mortgage bonds issued in May 2014. Proceeds from these sales were used to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes.

In June 2016, PSNC Energy issued $100 million of 4.13% senior notes due June 22, 2046. Proceeds from this sale were used to repay short-term debt, to finance capital expenditures, and for general corporate purposes.

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: 

	September 30, 2016
Millions of dollars	Total		SCANA			Consolidated SCE&G			PSNC  Energy
Lines of credit:
Five-year, expiring December 2020	$	1,300.0	$	400.0		$	700.0		$	200.0
Fuel Company five-year, expiring December 2020	$	500.0	—			$	500.0		—
Three-year, expiring December 2018	$	200.0	—			$	200.0		—
Total committed long-term	$	2,000.0	$	400.0		$	1,400.0		$	200.0
Outstanding commercial paper (270 or fewer days)	$	777.6	$	16.0		$	714.2		$	47.4
Weighted average interest rate			0.93		%	0.84		%	0.83		%
Letters of credit supported by LOC	$	3.3	$	3.0		$	0.3		—
Available	$	1,219.1	$	381.0		$	685.5		$	152.6

	December 31, 2015
Millions of dollars	Total		SCANA			Consolidated SCE&G			PSNC  Energy
Lines of credit:
Five-year, expiring December 2020	$	1,300.0	$	400.0		$	700.0		$	200.0
Fuel Company five-year, expiring December 2020	$	500.0	—			$	500.0		—
Three-year, expiring December 2018	$	200.0	—			$	200.0		—
Total committed long-term	$	2,000.0	$	400.0		$	1,400.0		$	200.0
Outstanding commercial paper (270 or fewer days)	$	531.4	$	37.4		$	420.2		$	73.8
Weighted average interest rate			1.19		%	0.74		%	0.77		%
Letters of credit supported by LOC	$	3.3	$	3.0		$	0.3		—
Available	$	1,465.4	$	359.6		$	979.6		$	126.2

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.

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    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 September 30, 2016, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $28.1 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 its balance sheet, Consolidated SCE&G includes amounts due from an affiliate within Receivables-affiliated companies and amounts due to an affiliate 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 income tax returns to claim certain tax-defined research and experimentation deductions and credits and to reflect related impacts on other items such as domestic production activities deductions. SCANA also made similar claims in filing its original 2013 and 2014 returns in 2014 and 2015, respectively.  In September 2016, SCANA claimed significant research and experimentation deductions and credits (offset by reductions in its domestic production activities deductions), related to the ongoing design and construction activities of the New Units, in its 2015 income tax returns. These claims followed the issuance of final IRS regulations in 2014 regarding such treatment with respect to expenditures related to the design and construction of pilot models. 

The IRS examined the claims in the amended returns, and as such examination of claims progressed without resolution, the Company and Consolidated SCE&G evaluated and recorded adjustments to unrecognized tax benefits; however, none of these changes materially affected the Company's and Consolidated SCE&G's effective tax rate. In October 2016, the examination of the amended tax returns progressed to appeals. In addition, the IRS has begun an examination of SCANA's 2013 through 2015 income tax returns.

These income tax deductions and credits are considered to be uncertain tax positions, and under relevant accounting guidance, estimates of the amounts of related tax benefits which may not be sustained upon examination by the taxing authorities are required to be recorded as unrecognized tax benefits in the financial statements. In connection with all of these federal and related state filings, the Company and Consolidated SCE&G have recorded an unrecognized tax benefit of $276 million ($254 million, net of the impact of the state deduction on the federal return). If recognized, $17 million of the tax benefit would affect the Company’s and Consolidated SCE&G's effective tax rate (see discussion below regarding deferral of benefits related to 2015 forward). It is reasonably possible that these unrecognized tax benefits may increase by an additional $228 million within the next 12 months as additional expenditures giving rise to tax benefits are incurred. It is also reasonably possible that these unrecognized tax benefits may decrease by $49 million within the next 12 months if the claims on amended returns which are currently in appeals are resolved. No other material changes in the status of the Company’s or Consolidated SCE&G's tax positions have occurred through September 30, 2016.

In connection with the research and experimentation deduction and credit claims reflected on the 2015 income tax returns and the expectation of similar claims to be made in determining 2016’s taxable income, the Company and Consolidated SCE&G have recorded regulatory assets for estimated foregone domestic production activities deductions, offset by estimated credits, and expect that such (net) deferred costs, along with any interest (see below) and other related deferred costs, will be recoverable through customer rates in future years. SCE&G's current customer rates reflect the availability of domestic production activities deductions (see Note 2).

Estimated interest expense accrued with respect to the unrecognized tax benefits related to the research and experimentation deductions in the 2015 income tax returns has been deferred as a regulatory asset and is expected to be recoverable through customer rates in future years. See also Note 2. Otherwise, the Company and Consolidated SCE&G recognize interest accrued related to unrecognized tax benefits within interest expense or interest income and recognize tax penalties within other expenses.  Amounts recorded for such interest income, interest expense or tax penalties have not been material.

On August 2, 2016, the State of North Carolina announced the lowering of its corporate income tax rate from 4% to 3% effective January 1, 2017. This reduction did not have a material impact on the Company's financial position, results of operations or cash flows.

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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 in which swaps designated as cash flow hedges are used to synthetically convert variable rate debt to fixed rate debt, periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense.

Forward starting swap agreements that are designated as cash flow hedges may be used in anticipation of the issuance of debt.  Except as described in the following paragraph, the effective portions of changes in fair value and payments made or received upon termination of such agreements for regulated subsidiaries are recorded in regulatory assets or regulatory liabilities. For SCANA and 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 related to them are recorded as regulatory assets and

25

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 September 30, 2016
Commodity contracts	8,600,000	11,781,000	4,223,500	24,604,500
Energy management contracts (a)	—	—	35,795,914	35,795,914
Total (a)	8,600,000	11,781,000	40,019,414	60,400,414
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 1,028,115 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	September 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
Designated as hedging instruments	$	115.6	$	120.0	$	36.4	$	36.4
Not designated as hedging instruments	1,285.0		1,235.0		1,285.0		1,235.0

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

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Fair Values of Derivative Instruments
		The Company				Consolidated SCE&G
Millions of dollars	Balance Sheet Location	Asset		Liability		Asset		Liability
As of September 30, 2016
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	3			$	1
	Other deferred credits and other liabilities			39				14
Commodity contracts
	Other current assets	$	3	1
Total		$	3	$	43	—		$	15
Not designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	47			$	47
	Other deferred credits and other liabilities			172				172
Commodity contracts
	Other current assets	$	3
Energy management contracts
	Other current assets	4
	Other deferred debits and other assets	2
	Derivative financial instruments			4
	Other deferred credits and other liabilities			2
Total		$	9	$	225	—		$	219
As of December 31, 2015
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	4			$	1
	Other deferred credits and other liabilities			28				9
Commodity contracts
	Other current assets			1
	Derivative financial instruments			4
Total		—		$	37	—		$	10
Not designated as hedging instruments
Interest rate contracts
	Other current assets	$	10			$	10
	Other deferred debits and other assets	5				5
	Derivative financial instruments			$	33			$	33
	Other deferred credits and other liabilities			22				22
Commodity contracts
	Other current assets	1
Energy management contracts
	Other current assets	11		2
	Other deferred debits and other assets	3
	Derivative financial instruments			9
	Other deferred credits and other liabilities			3
Total		$	30	$	69	$	15	$	55

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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 September 30,
Interest rate contracts	$	(1	)	$	(3	)	Interest expense	$	(1	)	$	(1	)
Nine Months Ended September 30,
Interest rate contracts	$	(6	)	$	(3	)	Interest expense	$	(2	)	$	(2	)

The Company:
	Gain (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 September 30,
Interest rate contracts	$	1		$	(3	)	Interest expense	$	(2	)	$	(2	)
Commodity contracts	(2		)	(4		)	Gas purchased for resale	—			(1		)
Total	$	(1	)	$	(7	)		$	(2	)	$	(3	)
Nine Months Ended September 30,
Interest rate contracts	$	(4	)	$	(3	)	Interest expense	$	(6	)	$	(6	)
Commodity contracts	—			(5		)	Gas purchased for resale	(6		)	(10		)
Total	$	(4	)	$	(8	)		$	(12	)	$	(16	)

As of September 30, 2016, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $1.7 million as a decrease to gas cost, assuming natural gas markets remain at their current levels, and approximately $6.6 million as an increase to interest expense.  As of September 30, 2016, all of the Company’s commodity cash flow hedges settle by their terms before the end of the third quarter of 2019.

As of September 30, 2016, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $1.9 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 (Loss) Reclassified from Deferred Accounts into Income
Millions of dollars	2016			2015			Location	2016			2015
Three Months Ended September 30,
Interest rate contracts	$	(24	)	$	(116	)	Other income	$	(1	)	—
Nine Months Ended September 30,
Interest rate contracts	$	(268	)	$	(79	)	Other income	$	(1	)	$	5

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As of September 30, 2016, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from derivatives not designated as hedges will include $2.3 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	September 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
in Net Liability Position
Aggregate fair value of derivatives in net liability position	$	263.3	$	95.2	$	234.2	$	57.0
Fair value of collateral already posted	171.5		50.4		140.4		13.4
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	91.8		44.8		93.8		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 $6.0 million in commodity derivatives that are in a net asset position at September 30, 2016, compared to letters of credit in the amount 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.

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Information related to the offsetting of derivative assets and derivative liabilities 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 September 30, 2016
Gross Amounts of Recognized Assets				$	6		$	6		$	12
Gross Amounts Offset in Statement of Financial Position				(1		)	(1		)	(2		)
Net Amounts Presented in Statement of Financial Position	—			5			5			10			—
Gross Amounts Not Offset - Financial Instruments										—
Gross Amounts Not Offset - Cash Collateral Received										—
Net Amount	—			$	5		$	5		$	10		—
Balance sheet location
Other current assets										$	8
Other deferred debits and other assets										2
Total										$	10		—
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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Derivative Liabilities	The Company												Consolidated SCE&G
Millions of dollars	Interest Rate Contracts			Commodity Contracts			Energy Management Contracts			Total			Interest Rate Contracts
As of September 30, 2016
Gross Amounts of Recognized Liabilities	$	261		$	1		$	6		$	268		$	234
Gross Amounts Offset in Statement of Financial Position				(1		)	(1		)	(2		)
Net Amounts Presented in Statement of Financial Position	261			—			5			266			234
Gross Amounts Not Offset - Financial Instruments										—
Gross Amounts Not Offset - Cash Collateral Posted	(169		)				(2		)	(171		)	(140		)
Net Amount	$	92		$	—		$	3		$	95		$	94
Balance sheet location
Derivative financial instruments										$	53		$	48
Other deferred credits and other liabilities										213			186
Total										$	266		$	234
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:

	As of September 30, 2016						As of December 31, 2015
	The Company				Consolidated SCE&G		The Company				Consolidated SCE&G
Millions of dollars	Level 1		Level 2		Level 2		Level 1		Level 2		Level 2
Assets:
Available for sale securities	$	14	—		—		$	11	—		—
Held to maturity securities	—		$	7	—		—		—		—
Interest rate contracts	—		—		—		—		$	15	$	15
Commodity contracts	6		—		—		1		—		—
Energy management contracts	1		5		—		—		14		—
Liabilities:
Interest rate contracts	—		261		$	234	—		87		65
Commodity contracts	1		—		—		1		4		—
Energy management contracts	—		9		—		4		12		—

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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	September 30, 2016				December 31, 2015
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
The Company	$	6,588.6	$	7,674.0	$	5,997.6	$	6,445.7
Consolidated SCE&G	$	5,264.9	$	6,189.1	$	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 September 30,
Service cost	$	4.4		$	6.6		$	0.8	$	1.2
Interest cost	9.8			9.6			3.0		2.8
Expected return on assets	(13.8		)	(15.5		)	—		—
Prior service cost amortization	1.0			1.0			0.1		0.1
Amortization of actuarial losses	3.7			3.2			0.2		0.4
Net periodic benefit cost	$	5.1		$	4.9		$	4.1	$	4.5

Nine months ended September 30,
Service cost	$	15.5		$	18.1		$	3.3	$	4.0
Interest cost	29.5			28.7			9.1		8.6
Expected return on assets	(41.9		)	(46.5		)	—		—
Prior service cost amortization	3.0			3.0			0.2		0.3
Amortization of actuarial losses	11.1			10.2			0.4		1.5
Net periodic benefit cost	$	17.2		$	13.5		$	13.0	$	14.4

Consolidated SCE&G	Pension Benefits						Other Postretirement Benefits
	2016			2015			2016		2015
Three months ended September 30,
Service cost	$	3.6		$	5.3		$	0.7	$	1.0
Interest cost	8.3			8.1			2.5		2.2
Expected return on assets	(11.7		)	(13.0		)	—		—
Prior service cost amortization	0.8			0.8			0.1		0.1
Amortization of actuarial losses	3.2			2.7			0.1		0.3
Net periodic benefit cost	$	4.2		$	3.9		$	3.4	$	3.6

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Nine months ended September 30,
Service cost	$	12.7		$	14.5		$	2.7	$	3.2
Interest cost	25.0			24.1			7.5		6.8
Expected return on assets	(35.5		)	(39.1		)	—		—
Prior service cost amortization	2.5			2.5			0.2		0.2
Amortization of actuarial losses	9.4			8.6			0.3		1.2
Net periodic benefit cost	$	14.1		$	10.6		$	10.7	$	11.4

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 $2.33 billion resulting from an event of a non-nuclear origin. In addition, a builder's risk insurance policy has been purchased from NEIL for the construction of the New Units. This policy provides the owners of the New Units up to $500 million of total coverage for accidental property damage occurring during construction. The NEIL policies, in the aggregate, are subject to a maximum loss of $2.75 billion for any single loss occurrence. All of the NEIL policies permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $45.8 million. SCE&G currently maintains an excess property insurance policy (for itself and on behalf of Santee Cooper) with EMANI. The policy provides coverage to 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 September 30, 2016, SCE&G’s investment in the New Units, including related transmission, totaled $4.2 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 Unit 2 and Unit 3 runs through the reinforced concrete activities necessary to support placement of shield building panels and the completion of shield building construction. 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 the critical path 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 initially 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. However, the Consortium continued to refine and update the Revised, Fully-Integrated Construction Schedule as certain designs were finalized, as construction progressed, and as additional information was received. See discussion of October 2015 Amendment below.

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 estimated gross construction cost (including escalation and AFC) were estimated to be $5.2 billion and $6.8 billion, respectively. These projections included 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 was to 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. However, see discussion of May 2016 Petition and September 2016 Settlement Agreement below.

October 2015 Amendment

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,

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upon the consummation of the acquisition by WEC of the stock of Stone & Webster from CB&I. Following that acquisition, Stone & Webster continues to be a member of the Consortium as a subsidiary of WEC rather than CB&I, and WEC has engaged Fluor as a subcontracted construction manager.

Among other things, the October 2015 Amendment:

(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) provided 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) provided 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,

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

(vii) provided for an explicit definition of Change in Law designed to reduce the likelihood of certain future commercial disputes, with the Consortium also acknowledging and agreeing that the project scope includes providing New Units that meet the standards of the NRC approved Design Control Document Revision 19,

(viii) established a DRB process for certain commercial claims and disputes, and

(ix) eliminated the requirement or ability of any party to bring suit regarding disputes before substantial completion of the project.

The DRB is comprised of three members chosen by the parties to resolve construction-related claims.  Amounts in dispute of less than $5 million will be resolved by the DRB without recourse, and amounts in dispute greater than $5 million will be resolved by the DRB for the remainder of the construction of the New Units, with a reserved right to further arbitrate or to litigate such issues at the conclusion of construction.

Under the October 2015 Amendment, SCE&G’s total estimated project costs increased 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 a result, SCE&G's estimated gross construction cost for the project (including the effects of these change orders, escalation and AFC but excluding the fixed price option described below) totaled approximately $7.2 billion.

The October 2015 Amendment also provided 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 reduced by amounts paid since June 30, 2015. Under the fixed price option, the aggregate delay-related liquidated damages referred to in (iii) above would be capped at $338 million per New Unit (SCE&G’s 55% portion being approximately $186 million per New 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). See information below regarding the execution of this fixed price option, subject to SCPSC approval.

WEC has engaged Fluor to review and confirm the project schedule. The owners understand that this process has not been completed. The analysis by Fluor, to the extent that it is shared with the owners, could affect the owners’ expectations regarding the project schedule. In a discussion of the project status on September 26, 2016, and in response to SCE&G’s

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specific questioning regarding work crew efficiency and productivity and schedule mitigation efforts, WEC executive management stated that it had no reason to believe that the August 2019 and 2020 guaranteed completion dates would not be met. WEC submits monthly schedule updates, however, and it has reported that there are significant risks to achieving the current guaranteed substantial completion dates. WEC has also reported that it is continuing to develop detailed mitigation plans to address those risks.

May 2016 Petition and September 2016 Settlement Agreement

On May 26, 2016, SCE&G petitioned the SCPSC seeking approval to update the capital cost schedule and construction milestone schedule for the New Units consistent with the October 2015 Amendment. Within this petition, SCE&G also informed the SCPSC that it had notified WEC of its intent to elect the fixed price option, subject to concurrence by Santee Cooper and approval by the SCPSC. The petition reflected an increase in total project costs of approximately $852 million over the cost approved by the SCPSC in September 2015, of which approximately $505 million is directly attributable to the fixed price option. SCE&G's estimated gross construction cost for the project is now estimated to be approximately $7.7 billion, including owner’s costs, transmission, escalation and AFC. After receiving Santee Cooper's concurrence in June 2016, SCE&G executed the fixed price option on July 1, 2016, subject to SCPSC approval.

On July 1, 2016, SCE&G amended the May 26, 2016 petition by withdrawing its request to adjust its transmission capital costs forecast in the amount of $4.3 million and revising its proposed capital cost schedule accordingly (along with the associated escalation and AFC). This revision was made while SCE&G evaluates alternatives to installing additional capacitors in Summer Station's existing Unit 1 switchyard.

On September 1, 2016, SCE&G entered into a settlement agreement with ORS and certain other parties concerning SCE&G's May 26, 2016 petition. The settlement agreement supports approval of the fixed price option and the revised construction and capital cost schedules, including the guaranteed substantial completion dates of August 2019 and August 2020 for Units 2 and 3, respectively, and the inclusion of an additional $831 million in the capital cost schedule. The settling parties also agreed to revise the allowed return on equity for new nuclear construction from 10.5% to 10.25%. This revised return on equity would be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2017, until such time as the New Units are completed. In addition, SCE&G agreed that it will not file future requests to amend capital cost schedules prior to January 28, 2019. SCE&G also agreed that, in most circumstances, if the projected commercial operation date for Unit 2 is extended, the expiration of the January 28, 2019 moratorium will be extended by an equal amount of time. A public hearing on the petition, as amended, and the settlement agreement was held in October 2016, and the SCPSC is expected to issue its order in November 2016.

Construction Milestone Payment Schedule and Related DRB Activity

The October 2015 Amendment provided that the parties would agree upon a construction milestone payment schedule within five months of the effective date of the October 2015 Amendment or submit the issue to the DRB.  The parties agreed to two one-month extensions for discussion of the schedule through July 2016.  The parties were unable to reach an agreement on a schedule in that time period, and the owners referred the matter to the DRB on August 1, 2016. The dispute relates only to the timing of payments, with WEC asking for payments pursuant to a schedule which is more front loaded than the owners believe is appropriate. The total amount to be paid is not in dispute.

A hearing was held by the DRB on August 30 and 31, 2016, prior to which the parties filed statements of position and information to substantiate their respective positions. In connection with the DRB proceeding, WEC expressed concerns with the adoption of owners' proposed construction milestone payment schedule and indicated that the cash flow provided by that payment schedule may adversely affect WEC's ability to complete the project successfully.

On September 30, 2016, the parties received an order issued by the DRB instructing them to continue to work to develop a construction milestone payment schedule by November 3, 2016. The parties were unsuccessful in reaching an agreement by that date; therefore, the order provides that the DRB will conduct a further hearing on November 9, 2016, and will make a determination by November 30, 2016. During these efforts, payments will be made to WEC for October and November 2016 totaling $133 million (SCE&G's 55% portion being approximately $73.2 million) and $136.5 million (SCE&G's 55% portion being approximately $75.1 million), respectively. These payments are based on the DRB's findings concerning the approximate value of the work expected to be completed during these months and are in lieu of all other contractually-required payments related to (v) above during October and November 2016.

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Based upon the information that has been presented by WEC in connection with the hearing and with respect to the matters at issue generally, SCE&G cannot predict whether a decision by the DRB which is more favorable to the owners will adversely affect WEC’s ability to complete the project or the construction schedule and costs.

As of September 30, 2016, payments related to (i) above had been made totaling $187.5 million (SCE&G's 55% portion being approximately $103.1 million). Also as of September 30, 2016, payments related to (v) above had been made totaling $930 million (SCE&G's 55% portion being $511.5 million), which included payments made during the initial five-month period described above, as required under the contract and payments agreed upon by the parties during the extensions described above and during the period the DRB was reviewing the matter.

Payment and Performance Obligations

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 standby letters of credit in lieu of payment and performance bonds from WEC 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.

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 project costs that arise through such dispute resolution processes (including those reflected in the October 2015 Amendment described above), as well as other project 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 is subject to customary closing conditions, including receipt of necessary regulatory approvals. This transaction will not affect the payment obligations between the parties during construction 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, SCE&G’s projected cost would be approximately $850 million for the additional 5% interest being acquired from Santee Cooper if the fixed price option is approved by the SCPSC.

Nuclear Production Tax Credits

The IRS has notified SCE&G that, subject to a national megawatt capacity limitation, the electricity to be produced by each of the New Units (advanced nuclear units, as defined) would qualify for nuclear production tax credits under Section 45J of the IRC to the extent that such New Unit is operational before January 1, 2021 and other eligibility requirements are met. These nuclear production tax credits (related to SCE&G's 55% share of both New Units) could total as much as approximately $1.4 billion. Such credits would be earned over the first eight years of each New Unit's operations and would be realized by

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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 remains under review by the NRC and SCE&G does not anticipate any additional regulatory actions as a result of that review, but it cannot predict future regulatory activities or how such initiatives would impact construction or operation of the New Units.

Environmental

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 each state from one to three years to issue SIPs, which will ultimately define the specific compliance methodology that will be applied to existing units in that state. On February 9, 2016, the Supreme Court stayed the rule pending disposition of a petition of review of the rule in the Court of Appeals. The order of the Supreme Court has no immediate impact on SCE&G and GENCO or their generation operations. The Company and Consolidated SCE&G 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. The State of South Carolina has chosen to remain in the CSAPR program, even though recent court rulings exempted the state. This allows the state to remain compliant with regional haze standards. Air quality control installations that SCE&G and GENCO have already completed have positioned them to comply with the existing allowances set by the CSAPR. Any costs incurred to comply with CSAPR are expected to be recoverable through rates.

In April 2012, the EPA's MATS rule containing new standards for mercury and other specified air pollutants became effective. 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. In addition, SCE&G retired certain other coal-fired units during this time frame. The MATS rule has been the subject of ongoing litigation even while it remains in effect. Rulings on this litigation are not expected to have an impact on SCE&G or GENCO due to these retirements, conversions, and enhancements. 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

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SCE&G expect that wastewater treatment technology retrofits will be required at Williams and Wateree Stations. Any costs incurred to comply with the ELG Rule are expected to be recoverable through rates.

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

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

The Nuclear Waste Act required that the United States government accept and permanently dispose of high-level radioactive waste and spent nuclear fuel by January 31, 1998, and it imposed on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. SCE&G entered into a Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with the DOE in 1983. As of September 30, 2016, 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 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 $10.3 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 September 30, 2016, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $26.0 million and are included in regulatory assets.

Other

On October 8, 2016, Hurricane Matthew made landfall on the South Carolina coast affecting SCE&G’s service territory.  At its peak, more than 290,000 SCE&G electric customers were without service.  Incremental operation and maintenance costs to restore electric service will be applied to SCE&G’s SCPSC-approved storm damage reserve.  It is expected that such restoration costs will exceed the available balance of $2.0 million in SCE&G’s storm damage reserve, and SCE&G expects such additional costs to be deferred and recoverable through customers rates in future years. 

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 nine months ended September 30, 2015, operating income and net income for All Other include $235 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 September 30, 2016
Electric Operations	$	817	$	1		$	364		n/a
Gas Distribution	111		—			(14		)	n/a
Retail Gas Marketing	68		—			n/a			$	(3	)
Energy Marketing	97		35			n/a			2
All Other	—		100			—			(7		)
Adjustments/Eliminations	—		(136		)	(2		)	197
Consolidated Total	$	1,093	$	—		$	348		$	189

Nine Months Ended September 30, 2016
Electric Operations	$	2,035	$	4		$	784	n/a
Gas Distribution	538		1			79		n/a
Retail Gas Marketing	315		—			n/a		$	17
Energy Marketing	283		83			n/a		6
All Other	—		302			—		(14		)
Adjustments/Eliminations	—		(390		)	37		462
Consolidated Total	$	3,171	$	—		$	900	$	471

Three Months Ended September 30, 2015
Electric Operations	$	742	$	1		$	313		n/a
Gas Distribution	112		2			(13		)	n/a
Retail Gas Marketing	68		—			n/a			$	(3	)
Energy Marketing	146		34			n/a			(1		)
All Other	—		102			—			(9		)
Adjustments/Eliminations	—		(139		)	(8		)	162
Consolidated Total	$	1,068	$	—		$	292		$	149

Nine Months Ended September 30, 2015
Electric Operations	$	2,008		$	4		$	728	n/a
Gas Distribution	609			2			88		n/a
Retail Gas Marketing	344			—			n/a		$	18
Energy Marketing	461			101			n/a		8
All Other	5			309			237		188
Adjustments/Eliminations	(4		)	(416		)	42		434
Consolidated Total	$	3,423		$	—		$	1,095	$	648

Consolidated SCE&G
Millions of dollars	External Revenue		Operating Income			Earnings Available to Common Shareholder
Three Months Ended September 30, 2016
Electric Operations	$	818	$	364		n/a
Gas Distribution	64		(5		)	n/a
Adjustments/Eliminations	—		—			$	201
Consolidated Total	$	882	$	359		$	201

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Nine Months Ended September 30, 2016
Electric Operations	$	2,039	$	784	n/a
Gas Distribution	253		32		n/a
Adjustments/Eliminations	—		—		$	423
Consolidated Total	$	2,292	$	816	$	423

Three Months Ended September 30, 2015
Electric Operations	$	743	$	313		n/a
Gas Distribution	63		(6		)	n/a
Adjustments/Eliminations	—		—			$	164
Consolidated Total	$	806	$	307		$	164

Nine Months Ended September 30, 2015
Electric Operations	$	2,013	$	728	n/a
Gas Distribution	275		35		n/a
Adjustments/Eliminations	—		—		$	394
Consolidated Total	$	2,288	$	763	$	394

Segment Assets	The Company				Consolidated SCE&G
	September 30,		December 31,		September 30,		December 31,
Millions of dollars	2016		2015		2016		2015
Electric Operations	$	11,543	$	10,883	$	11,543	$	10,883
Gas Distribution	2,757		2,606		801		757
Retail Gas Marketing	140		106		n/a		n/a
Energy Marketing	58		95		n/a		n/a
All Other	985		998		n/a		n/a
Adjustments/Eliminations	2,963		2,458		3,634		3,125
Consolidated Total	$	18,446	$	17,146	$	15,978	$	14,765

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 $41.8 million and $66.3 million for the three months ended September 30, 2016 and 2015, respectively, and $138.6 million and $186.0 million for the nine months ended September 30, 2016 and 2015, respectively.  SCE&G’s total sales to this affiliate were $41.6 million and $65.9 million for the three months ended September 30, 2016 and 2015, respectively, and $137.8 million and $185.1 million for the nine months ended September 30, 2016 and 2015, respectively. SCE&G’s receivable from this affiliate was $4.0 million at September 30, 2016 and $12.8 million at December 31, 2015.  SCE&G’s payable to this affiliate was $4.1 million at September 30, 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 $34.8 million and $34 million for the three months ended September 30, 2016 and 2015, respectively, and $83.1 million and $101.4 million for the nine months ended September 30, 2016 and 2015, respectively.  SCE&G’s payables to SEMI for such purchases were $10.9 million at September 30, 2016 and $7.5 million at December 31, 2015.

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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, telecommunications, customer support, marketing and sales, human resources, corporate compliance, purchasing, financial, risk management, public affairs, legal, investor relations, gas supply and capacity management, strategic planning, general administrative, and retirement benefits. In addition, SCANA Services processes and pays invoices for Consolidated SCE&G and is reimbursed. Costs for these services were $80.4 million and $80.8 million for the three months ended September 30, 2016 and 2015, respectively, and $236.4 million and $226.0 million for the nine months ended September 30, 2016 and 2015, respectively. Consolidated SCE&G's payables to SCANA Services for these services were $50.8 million at September 30, 2016 and $57.0 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

RESULTS OF OPERATIONS

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2016

AS COMPARED TO THE CORRESPONDING PERIODS IN 2015

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.

Earnings Per Share

Earnings per share was as follows:

	Third Quarter				Year to Date
	2016		2015		2016		2015
Earnings per share	$	1.32	$	1.04	$	3.29	$	4.53

Third Quarter

Third quarter earnings per share increased primarily due to higher electric and gas distribution margins and higher other income, net of other expenses. These increases were partially offset by higher other operation and maintenance expenses, higher depreciation expense, higher property taxes and higher interest cost, as further discussed below.

Year to Date

Year to date earnings per share decreased primarily due to the gains on the sales of CGT and SCI in the first quarter of 2015. Higher electric and gas distribution margins and higher other income, net of other expenses, were partially offset by lower retail gas and energy marketing net income, higher other operation and maintenance expenses, higher depreciation expense, higher property taxes and higher interest cost, as further discussed below.

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.

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
July 28, 2016	$0.575	September 12, 2016	October 1, 2016
October 27, 2016	$0.575	December 12, 2016	January 1, 2017

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:

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	Third Quarter						Year to Date
Millions of dollars	2016		Change		2015		2016		Change		2015
Operating revenues	$	818.4	10.1	%	$	743.6	$	2,038.5	1.3	%	$	2,012.7
Less:  Fuel used in electric generation	176.4		(5.5	)%	186.7		442.9		(15.6	)%	524.8
Purchased power	21.0		50.0	%	14.0		49.6		29.5	%	38.3
Margin	621.0		14.4	%	542.9		1,546.0		6.7	%	1,449.6
Other operation and maintenance	130.0		2.9	%	126.3		389.9		6.2	%	367.3
Depreciation and amortization	71.9		30.3	%	55.2		213.4		2.8	%	207.5
Other taxes	55.4		14.0	%	48.6		159.0		8.5	%	146.6
Operating Income	$	363.7	16.3	%	$	312.8	$	783.7	7.6	%	$	728.2

Electric operations can be significantly impacted by the effects of weather. SCE&G estimates the effects on its electric business of actual temperatures in its service territory as compared to historical averages to develop an estimate of electric margin revenue attributable to the effects of abnormal weather. Third quarter weather in SCE&G’s electric service territory was warmer than normal in both 2016 and 2015; however, the third quarter of 2016 was warmer than the third quarter of 2015. In addition, year-to-date results reflect milder than normal weather in the first quarter of 2016 but colder than normal weather in the first quarter of 2015 and warmer than normal second quarter weather in both 2016 and 2015.

Third Quarter

• Margin increased due to base rate increases under the BLRA of $19.0 million, the effects of warmer weather of $33.6 million, residential and commercial customer growth of $6.3 million, higher industrial margin of $3.8 million and higher collections under SCE&G’s rate rider for pension costs of $5.6 million. The higher pension rider collections had no effect on net income as they were fully offset by the recognition, within other operation and maintenance expenses, of higher pension costs. Margin also increased due to a downward revenue adjustment in 2015, pursuant to an order from the SCPSC, to apply $14.5 million as an offset to fuel cost recovery upon the adoption of new (lower) electric depreciation rates. This adjustment had no effect on net income in 2015 as it was fully offset by the recognition of $14.5 million of lower depreciation expense. These margin increases were partially offset by lower residential and commercial average use of $3.0 million.

• Other operation and maintenance expenses increased due to higher labor costs of $5.2 million, primarily due to increased pension cost associated with the higher pension rider collections and higher incentive compensation costs.

• Depreciation and amortization increased by $14.5 million due to the effects of the implementation of SCPSC-approved revised (lower) depreciation rates in the third quarter of 2015 and by net plant additions.

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

Year to Date

• Margin increased due to base rate increases under the BLRA of $50.1 million, the effects of weather of $10.0 million, residential and commercial customer growth of $17.3 million, higher industrial margin of $3.2 million and higher collections under SCE&G’s rate rider for pension costs of $9.3 million. The higher pension rider collections had no effect on net income as they were fully offset by the recognition, within other operation and maintenance expenses, of higher pension costs. Margin also increased due to downward revenue adjustments in 2015, pursuant to orders from the SCPSC, to apply $14.5 million as an offset to fuel cost recovery upon the adoption of new (lower) electric depreciation rates and by $5.2 million related to SCE&G’s DSM Programs. These adjustments had no effect on net income in 2015 as they were fully offset by the recognition of $14.5 million of lower depreciation expense and by the recognition, within other income, of $5.2 million of gains realized upon the adoption of certain interest rate contracts. These margin increases were partially offset by lower residential and commercial average use of $11.0 million.

• Other operation and maintenance expenses increased due to higher labor costs of $19.1 million, primarily due to increased pension cost associated with the higher pension rider collections and higher incentive compensation costs, and the amortization of $1.7 million of DSM Programs cost.

• Depreciation and amortization increased primarily due to net plant additions.

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

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

	Third Quarter				Year to Date
Classification	2016	Change		2015	2016	Change		2015
Residential	2,648	9.2	%	2,426	6,450	0.4	%	6,425
Commercial	2,259	5.4	%	2,143	5,861	1.9	%	5,754
Industrial	1,676	1.0	%	1,660	4,760	0.7	%	4,726
Other	171	3.6	%	165	462	0.9	%	458
Total Retail Sales	6,754	5.6	%	6,394	17,533	1.0	%	17,363
Wholesale	276	3.8	%	266	725	(3.2	)%	749
Total Sales	7,030	5.6	%	6,660	18,258	0.8	%	18,112

Third Quarter

Retail sales volumes increased primarily due to the effects of warmer weather and customer growth. These increases were partially offset by lower residential and commercial average use. Wholesale sales volumes also increased due to the effects of warmer weather.

Year to Date

Retail sales volumes increased primarily due to the effects of weather and customer growth. These increases were partially offset by lower residential and commercial average use.

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:

	Third Quarter								Year to Date
Millions of dollars	2016			Change		2015			2016		Change		2015
Operating revenues	$	111.9		(0.2	)%	$	112.1		$	539.3	(11.7	)%	$	610.7
Less:  Gas purchased for resale	51.2			(5.0	)%	53.9			238.2		(25.1	)%	317.9
Margin	60.7			4.3	%	58.2			301.1		2.8	%	292.8
Other operation and maintenance	42.9			0.7	%	42.6			129.7		8.6	%	119.4
Depreciation and amortization	20.8			7.2	%	19.4			60.9		5.5	%	57.7
Other taxes	10.4			11.8	%	9.3			31.3		11.8	%	28.0
Operating Income (Loss)	$	(13.4	)	2.3	%	$	(13.1	)	$	79.2	(9.7	)%	$	87.7

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.

Third Quarter and Year to Date

•Margin increased primarily due to customer growth.

• Other operation and maintenance expenses increased due to higher labor costs of $5.4 million for the year, primarily due to higher incentive compensation costs.

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

• Other taxes increased due to net plant additions.

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

	Third Quarter				Year to Date
Classification (in thousands)	2016	Change		2015	2016	Change		2015
Residential	2,073	0.2	%	2,069	27,055	(9.2	)%	29,786
Commercial	4,363	0.8	%	4,329	20,748	(2.3	)%	21,233
Industrial	4,493	(6.1	)%	4,786	14,380	(4.3	)%	15,024
Transportation	15,171	11.5	%	13,610	37,089	2.7	%	36,101
Total	26,100	5.3	%	24,794	99,272	(2.8	)%	102,144

Third Quarter

Residential and commercial firm sales volumes increased primarily due to customer growth. Industrial interruptible volumes decreased at SCE&G due to decreased demand from manufacturing customers partially offset by customer growth at PSNC Energy. Transportation volumes increased due to higher natural gas fired electric generation and customers shifting from system supply to transportation only service. 

Year to Date

Residential and commercial firm sales volumes decreased primarily due to the effects of milder winter weather partially offset by customer growth. Industrial interruptible sales volumes decreased due decreased demand from manufacturing customers. Transportation volumes increased primarily due to higher natural gas fired electric generation and customers shifting from system supply to transportation only service. 

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:

	Third Quarter								Year to Date
Millions of dollars	2016			Change		2015			2016		Change		2015
Operating revenues	$	68.9		1.5	%	$	67.9		$	315.3	(8.3	)%	$	344.0
Net income (loss)	(2.9		)	(25.6	)%	(3.9		)	16.8		(4.5	)%	17.6

Third Quarter

Net loss decreased due to lower operating costs.

Year to Date

Revenues and net income decreased primarily due to milder winter weather.

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:

	Third Quarter							Year to Date
Millions of dollars	2016		Change		2015			2016		Change		2015
Operating revenues	$	130.9	(27.4	)%	$	180.4		$	366.2	(34.9	)%	$	562.5
Net income (loss)	2.0		*		(0.6		)	6.1		(24.7	)%	8.1
* Greater than 100%

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Third Quarter

Revenues decreased primarily due to lower industrial volumes. Net income increased due to lower operating costs. 

Year to Date

Revenues and net income decreased primarily due to milder winter weather.

Other Operating Expenses

Other operating expenses were as follows:

	Third Quarter						Year to Date
Millions of dollars	2016		Change		2015		2016		Change		2015
Other operation and maintenance	$	186.6	2.6	%	$	181.8	$	557.9	5.9	%	$	527.0
Depreciation and amortization	93.2		24.3	%	75.0		276.1		3.3	%	267.3
Other taxes	66.3		13.7	%	58.3		191.8		8.8	%	176.3

Third Quarter

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

Year to Date

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:

	Third Quarter								Year to Date
Millions of dollars	2016			Change		2015			2016			Change		2015
Other income	$	15.8		(14.6	)%	$	18.5		$	46.4		(16.5	)%	$	55.6
Other expense	(7.1		)	(56.7	)%	(16.4		)	(31.5		)	(27.6	)%	(43.5		)
Gain on sale of SCI, net of transaction costs	—			—		—			—			(100.0	)%	106.6
AFC - equity funds	6.9			(15.9	)%	8.2			21.6			8.5	%	19.9

Third Quarter

Other income and other expense decreased by $5.8 million due to lower billings to DCGT for transition services provided at cost pursuant to the terms of the sale of CGT. The decrease in other income was partially offset by higher SCPSC-approved carrying costs on certain deferred amounts. AFC decreased due to lower AFC rates.

Year to Date

Other income and other expense decreased by $10.5 million due to lower billings to DCGT for transition services provided at cost pursuant to the terms of the sale of CGT. In addition, other income decreased by $3.9 million and other expense decreased by $2.3 million due to the sale of SCI. Also, other income decreased by $3.2 million due to lower gains on

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the sale of land and due to the recognition in 2015 of $5.2 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). Decreases in other income were partially offset by higher SCPSC-approved carrying costs on certain deferred amounts. In 2015 other income also included the gain on the sale of SCI.  AFC increased due to construction activity, partially offset by lower AFC rates.

Interest Expense

     Interest charges increased primarily due to increased borrowings.

Income Taxes

Income taxes for the three months ended September 30, 2016 were higher than those recognized in the same period in 2015 primarily due to higher income before taxes. Income taxes for the nine months ended September 30, 2016 were lower than the same period 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 those sales. 

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 nine and 12 months ended September 30, 2016 was 3.53 and 3.31, 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 September 30, 2016, the Company had net available liquidity of approximately $1.3 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.

In October 2016, SCE&G's authority from FERC to issue short-term indebtedness and to assume liabilities as a guarantor (pursuant to Section 204 of the Federal Power Act) was renewed. 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. Likewise, GENCO's authority from FERC to issue indebtedness with maturity dates of one year or less not to exceed $200 million outstanding was renewed in October 2016. The authority described herein will expire in October 2018.

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

Cash flows from investing activities in 2016 were related to capital expenditures and funding of collateral deposit requirements with respect to interest rate swaps as interest rates declined. 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 long-term debt and 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.

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On November 1, 2016, Consolidated SCE&G paid at maturity $100 million related to a nuclear fuel financing which had an imputed interest rate of 0.78%.

In June 2016, SCE&G issued $425 million of 4.1% first mortgage bonds due June 15, 2046. In addition, SCE&G issued $75 million of 4.5% first mortgage bonds due June 1, 2064, which constituted a reopening of $300 million of 4.5% first mortgage bonds issued in May 2014. Proceeds from these sales were used to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes.

In June 2016, PSNC issued $100 million of 4.13% senior notes due June 22, 2046. Proceeds from this sale were used to repay short-term debt, to finance capital expenditures, and for general corporate purposes.

SCE&G's current preliminary estimates of its capital expenditures for new nuclear construction (including transmission) for 2016 through 2018, which are subject to continuing review and adjustment, are $952 million in 2016, $1,335 million in 2017, and $968 million in 2018.

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.

Uncertain income tax positions

During 2013 and 2014, SCANA amended certain of its income tax returns to claim tax-defined research and experimentation deductions (under IRC Section 174) and credits (under IRC Section 41) and to reflect related impacts on other items such as domestic production activities deductions (under IRC Section 199). SCANA also made similar claims in filing its original 2013 and 2014 returns in 2014 and 2015, respectively. In September 2016, SCANA claimed significant research and experimentation deductions and credits (offset by reductions in its domestic production activities deductions), related to the ongoing design and construction activities of the New Units, in its 2015 tax returns. These claims followed the issuance of final IRS regulations in 2014 regarding expenditures related to the design and construction of pilot models.  See also Note 5 to the combined notes to the condensed consolidated financial statements.

These income tax deductions and credits are considered to be uncertain tax positions, and under relevant accounting guidance, estimates of the amounts of related tax benefits which may not be sustained upon examination by the taxing authorities are required to be recorded as unrecognized tax benefits in the financial statements.  As of September 30, 2016, such estimated unrecognized benefits totaled $276 million ($254 million, net of the impact of the state deduction on the federal return).  The estimates of unrecognized tax benefits were computed with consideration as to whether the claims are (or are not) more likely than not to be sustained and with consideration of analyses of cumulative probabilities regarding potential outcomes.  Such estimates involve significant management judgment and varying levels of precision.  Changes in such estimates are required to be recorded as circumstances change and additional information regarding the claims and potential outcomes becomes available.  Such changes in estimates could be significant.

However, as these uncertain tax positions primarily involve the timing of recognition of tax deductions rather than permanent tax attributes, the estimates regarding their recognition do not significantly impact the Company's effective tax rate.  Further, the permanent attributes (net), as well as most of the interest accruals required to be recorded with respect to the unrecognized tax benefits, have been deferred within regulatory assets.  As such, the impacts of these significant accounting estimates, and changes therein, are primarily reflected on the balance sheet rather than in results of operations.

Upon resolution of the uncertainties, SCANA will be required to pay any tax benefits claimed which are ultimately disallowed, along with interest on those amounts.  In certain circumstances, which the Company considers to be remote, penalties for underpayment of income taxes could also be assessed.

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

RESULTS OF OPERATIONS

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2016

AS COMPARED TO THE CORRESPONDING PERIODS IN 2015

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. 

Net Income

Net income for Consolidated SCE&G was as follows:

	Third Quarter						Year to Date
Millions of dollars	2016		Change		2015		2016		Change		2015
Net income	$	204.0	21.9	%	$	167.4	$	432.9	7.0	%	$	404.6

Third Quarter and Year to Date

Net income increased primarily due to higher electric and gas distribution margins, partially offset by higher other operation and maintenance expenses, higher depreciation expense, higher property taxes and higher interest cost, 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
July 28, 2016	$76.1 million	September 30, 2016	October 1, 2016
October 27, 2016	$79.1 million	December 31, 2016	January 1, 2017

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:

	Third Quarter						Year to Date
Millions of dollars	2016		Change		2015		2016		Change		2015
Operating revenues	$	818.4	10.1	%	$	743.6	$	2,038.5	1.3	%	$	2,012.7
Less: Fuel used in electric generation	176.4		(5.5	)%	186.7		442.9		(15.6	)%	524.8
Purchased power	21.0		50.0	%	14.0		49.6		29.5	%	38.3
Margin	621.0		14.4	%	542.9		1,546.0		6.7	%	1,449.6
Other operation and maintenance	133.6		3.2	%	129.4		400.1		6.2	%	376.6
Depreciation and amortization	68.8		30.8	%	52.6		204.7		2.5	%	199.8
Other taxes	54.9		14.1	%	48.1		157.5		8.7	%	144.9
Operating Income	$	363.7	16.3	%	$	312.8	$	783.7	7.6	%	$	728.3

Electric operations can be significantly impacted by the effects of weather. SCE&G estimates the effects on its electric business of actual temperatures in its service territory as compared to historical averages to develop an estimate of electric margin revenue attributable to the effects of abnormal weather. Third quarter weather in SCE&G’s electric service territory was warmer than normal in both 2016 and 2015; however, the third quarter of 2016 was warmer than the third quarter of 2015. In

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addition, year-to-date results reflect milder than normal weather in the first quarter of 2016 but colder than normal weather in the first quarter of 2015 and warmer than normal second quarter weather in both 2016 and 2015.

Third Quarter

• Margin increased due to base rate increases under the BLRA of $19.0 million, the effects of warmer weather of $33.6 million, residential and commercial customer growth of $6.3 million, higher industrial margin of $3.8 million and higher collections under SCE&G’s rate rider for pension costs of $5.6 million. The higher pension rider collections had no effect on net income as they were fully offset by the recognition, within other operation and maintenance expenses, of higher pension costs. Margin also increased due to a downward revenue adjustment in 2015, pursuant to an order from the SCPSC, to apply $14.5 million as an offset to fuel cost recovery upon the adoption of new (lower) electric depreciation rates. This adjustment had no effect on net income in 2015 as it was fully offset by the recognition of $14.5 million of lower depreciation expense. These margin increases were partially offset by lower residential and commercial average use of $3.0 million.

• Other operation and maintenance expenses increased due to higher labor costs of $5.2 million, primarily due to increased pension cost associated with the higher pension rider collections and higher incentive compensation costs.

• Depreciation and amortization increased by $14.5 million due to the effects of the implementation of SCPSC-approved revised (lower) depreciation rates in the third quarter of 2015 and by net plant additions.

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

Year to Date

• Margin increased due to base rate increases under the BLRA of $50.1 million, the effects of weather of $10.0 million, residential and commercial customer growth of $17.3 million, higher industrial margin of $3.2 million and higher collections under SCE&G’s rate rider for pension costs of $9.3 million. The higher pension rider collections had no effect on net income as they were fully offset by the recognition, within other operation and maintenance expenses, of higher pension costs. Margin also increased due to downward revenue adjustments in 2015, pursuant to orders from the SCPSC, to apply $14.5 million as an offset to fuel cost recovery upon the adoption of new (lower) electric depreciation rates and by $5.2 million related to SCE&G’s DSM Programs. These adjustments had no effect on net income in 2015 as they were fully offset by the recognition of $14.5 million of lower depreciation expense and by the recognition, within other income, of $5.2 million of gains realized upon the adoption of certain interest rate contracts. These margin increases were partially offset by lower residential and commercial average use of $11.0 million.

• Other operation and maintenance expenses increased due to higher labor costs of $19.1 million, primarily due to increased pension cost associated with the higher pension rider collections and higher incentive compensation costs, and the amortization of $1.7 million of DSM Programs cost.

• Depreciation and amortization increased primarily due to net plant additions.

• Other taxes increased primarily due 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:

	Third Quarter				Year to Date
Classification	2016	Change		2015	2016	Change		2015
Residential	2,648	9.2	%	2,426	6,450	0.4	%	6,425
Commercial	2,259	5.4	%	2,143	5,861	1.9	%	5,754
Industrial	1,676	1.0	%	1,660	4,760	0.7	%	4,726
Other	171	3.6	%	165	462	0.9	%	458
Total Retail Sales	6,754	5.6	%	6,394	17,533	1.0	%	17,363
Wholesale	276	3.8	%	266	725	(3.2	)%	749
Total Sales	7,030	5.6	%	6,660	18,258	0.8	%	18,112

Third Quarter

Retail sales volumes increased primarily due to the effects of warmer weather and customer growth. These increases were partially offset by lower residential and commercial average use. Wholesale sales volumes also increased due to the effects of warmer weather.

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Year to Date

Retail sales volumes increased primarily due to the effects of weather and customer growth. These increases were partially offset by lower residential and commercial average use.

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:

	Third Quarter								Year to Date
Millions of dollars	2016			Change		2015			2016		Change		2015
Operating revenues	$	64.0		2.1	%	$	62.7		$	253.2	(7.9	)%	$	274.8
Less: Gas purchased for resale	36.5			(0.5	)%	36.7			126.0		(16.4	)%	150.8
Margin	27.5			5.8	%	26.0			127.2		2.6	%	124.0
Other operation and maintenance	18.4			(0.5	)%	18.5			54.1		5.9	%	51.1
Depreciation and amortization	6.8			1.5	%	6.7			20.3		1.5	%	20.0
Other taxes	7.0			14.8	%	6.1			20.3		9.7	%	18.5
Operating Income (Loss)	$	(4.7	)	(11.3	)%	$	(5.3	)	$	32.5	(5.5	)%	$	34.4

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.

Third Quarter and Year to Date

• Margin increased primarily due to customer growth.

• Other operation and maintenance expenses increased due to higher labor costs of $1.4 million for the year, primarily due to higher incentive compensation costs.

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

• Other taxes increased due to net plant additions.

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

	Third Quarter				Year to Date
Classification (in thousands)	2016	Change		2015	2016	Change		2015
Residential	696	0.1	%	695	8,473	(9.1	)%	9,320
Commercial	2,295	(0.3	)%	2,302	9,361	(1.6	)%	9,513
Industrial	4,141	(7.3	)%	4,468	12,762	(4.3	)%	13,336
Transportation	1,252	10.0	%	1,138	3,747	7.5	%	3,486
Total	8,384	(2.5	)%	8,603	34,343	(3.7	)%	35,655

Third Quarter

Industrial interruptible volumes decreased due to decreased demand from manufacturing customers. Transportation volumes increased due to customers shifting from system supply to transportation only service. 

Year to Date

Residential and commercial firm sales volumes decreased primarily due to the effects of milder winter weather partially offset by customer growth. Industrial interruptible sales volumes decreased due to decreased demand from manufacturing customers.  Transportation volumes increased primarily due to customers shifting from system supply to transportation only service. 

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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:

	Third Quarter								Year to Date
Millions of dollars	2016			Change		2015			2016			Change		2015
Other income	$	7.3		17.7	%	$	6.2		$	19.6		(18.3	)%	$	24.0
Other expense	(4.6		)	(31.3	)%	(6.7		)	(18.8		)	(10.0	)%	(20.9		)
AFC - equity funds	6.4			(13.5	)%	7.4			18.7			1.6	%	18.4

Third Quarter

Other income increased primarily due to higher SCPSC-approved carrying costs on certain deferred amounts. AFC decreased due to lower AFC rates.

Year to Date

Other income decreased primarily due to lower gains on the sale of land of $3.2 million and the recognition in 2015 of $5.2 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). Decreases in other income were partially offset by higher SCPSC-approved carrying costs on certain deferred amounts. AFC increased due to construction activity, partially offset by lower AFC rates.

Interest Expense

Interest charges increased primarily due to increased borrowings.

Income Taxes

Income taxes for the three and nine months ended September 30, 2016 were higher than the same periods in 2015 primarily due to higher income before taxes.

LIQUIDITY AND CAPITAL RESOURCES

Consolidated SCE&G anticipates that its cash obligations will be met through internally-generated funds and additional short- and long-term borrowings.  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 nine and 12 months ended September 30, 2016 was 3.94 and 3.62, 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 September 30, 2016, Consolidated SCE&G had net available liquidity of approximately $714.0 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 24 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.

In October 2016, SCE&G's authority from FERC to issue short-term indebtedness and to assume liabilities as a guarantor (pursuant to Section 204 of the Federal Power Act) was renewed. 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. Likewise, GENCO's authority from FERC to issue indebtedness with maturity dates of one year or less not to exceed $200 million outstanding was renewed in October 2016. The authority described herein will expire in October 2018.

Cash provided from operating activities decreased primarily due to tax payments in 2016. Tax payments in 2015 were impacted by Congress' extension of bonus depreciation provisions late in 2014.

Cash flows from investing activities in 2016 and 2015 were 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 long-term debt and equity contributions from SCANA.

On November 1, 2016, Consolidated SCE&G paid at maturity $100 million related to a nuclear fuel financing which had an imputed interest rate of 0.78%.

In June 2016, SCE&G issued $425 million of 4.1% first mortgage bonds due June 15, 2046. In addition, SCE&G issued $75 million of 4.5% first mortgage bonds due June 1, 2064, which constituted a reopening of $300 million of 4.5% first mortgage bonds issued in May 2014. Proceeds from these sales were used to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes.

SCE&G's current preliminary estimates of its capital expenditures for new nuclear construction (including transmission) for 2016 through 2018, which are subject to continuing review and adjustment, are $952 million in 2016, $1,335 million in 2017, and $968 million in 2018.

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.

Uncertain income tax positions

Consolidated SCE&G is included in the consolidated federal income tax returns of SCANA. During 2013 and 2014, SCANA amended certain of its income tax returns to claim tax-defined research and experimentation deductions (under IRC Section 174) and credits (under IRC Section 41) and to reflect related impacts on other items such as domestic production activities deductions (under IRC Section 199). SCANA also made similar claims in filing its original 2013 and 2014 returns in 2014 and 2015, respectively. In September 2016, SCANA claimed significant research and experimentation deductions and credits (offset by reductions in its domestic production activities deductions), related to the ongoing design and construction activities of the New Units, in its 2015 tax returns. These claims followed the issuance of final IRS regulations in 2014 regarding expenditures related to the design and construction of pilot models.  See also Note 5 to the combined notes to the condensed consolidated financial statements.

These income tax deductions and credits are considered to be uncertain tax positions, and under relevant accounting guidance, estimates of the amounts of related tax benefits which may not be sustained upon examination by the taxing authorities are required to be recorded as unrecognized tax benefits in the financial statements.  As of September 30, 2016, such estimated unrecognized benefits totaled $276 million ($254 million, net of the impact of the state deduction on the federal return).  The estimates of unrecognized tax benefits were computed with consideration as to whether the claims are (or are not) more likely than not to be sustained and with consideration of analyses of cumulative probabilities regarding potential outcomes.  Such estimates involve significant management judgment and varying levels of precision.  Changes in such estimates are required to be recorded as circumstances change and additional information regarding the claims and potential outcomes becomes available.  Such changes in estimates could be significant.

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However, as these uncertain tax positions primarily involve the timing of recognition of tax deductions rather than permanent tax attributes, the estimates regarding their recognition do not significantly impact Consolidated SCE&G's effective tax rate.  Further, the permanent attributes (net), as well as most of the interest accruals required to be recorded with respect to the unrecognized tax benefits, have been deferred within regulatory assets.  As such, the impacts of these significant accounting estimates, and changes therein, are primarily reflected on the balance sheet rather than in results of operations.

Upon resolution of the uncertainties, SCANA will be required to pay any tax benefits claimed which are ultimately disallowed, along with interest on those amounts.  In certain circumstances, which Consolidated SCE&G considers to be remote, penalties for underpayment of income taxes could also be assessed.

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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.

Expected Maturity	2016	2017	2018	2019
Futures - Long
Settlement Price (a)	3.04	3.19	3.21
Contract Amount (b)	14.8	37.0	2.7
Fair Value (b)	16.1	38.7	2.8
Futures - Short
Settlement Price (a)	3.02	3.20
Contract Amount (b)	0.7	0.9
Fair Value (b)	0.8	1.0
Options - Purchased Call (Long)
Strike Price (a)	1.99	2.00
Contract Amount (b)	9.2	16.5
Fair Value (b)	0.8	1.9
Swaps - Commodity
Pay fixed/receive variable (b)	7.0	13.2	6.4	0.6
Average pay rate (a)	3.2627	3.4200	3.4975	2.8892
Average received rate (a)	3.0194	3.1322	2.9522	2.9713
Fair value (b)	6.5	12.1	5.4	0.6
Pay variable/receive fixed (b)	8.0	19.2	5.6	0.4
Average pay rate (a)	3.0210	3.1314	2.9926	3.0088
Average received rate (a)	3.1548	3.2783	3.4991	2.8941
Fair value (b)	8.4	20.1	6.5	0.4
Swaps - Basis
Pay variable/receive variable (b)	0.9	1.3	0.7	0.3
Average pay rate (a)	3.0336	3.1998	3.0375	3.0999
Average received rate (a)	2.9804	3.1443	2.9943	3.0299
Fair value (b)	0.9	1.3	0.7	0.3
(a) Weighted average, in dollars
(b) Millions of dollars

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ITEM 4. CONTROLS AND PROCEDURES

As of September 30, 2016, the Registrants have evaluated, under the supervision and with the participation of management, including the CEO and CFO, (a) the effectiveness of the design and operation of disclosure controls and procedures and (b) any change in internal control over financial reporting.  Based on this evaluation, the CEO and CFO concluded that, as of September 30, 2016, these disclosure controls and procedures were effective. There has been no change in internal control over financial reporting during the quarter ended September 30, 2016 that has materially affected or is reasonably likely to materially affect internal control over financial reporting for either of the Registrants.

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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
July 1-31	6,614	$	74.51	6,614
August 1 - 31	621	71.55		621
September 1 - 30	—	—		—
Total	7,235			7,235	*

*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.

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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: November 4, 2016		James E. Swan, IV
		Vice President and Controller
		(Principal accounting officer)

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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.

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EX-12.01

Exhibit 12.01

COMPUTATION OF RATIOS

September 30, 2016

RATIO OF EARNINGS TO FIXED CHARGES

SCANA:	Nine Months Ended September 30, 2016			Twelve Months Ended September 30, 2016			Years ended December 31,
Dollars in Millions							2015		2014			2013			2012			2011
Fixed Charges as defined:
Interest on debt		$264.8			$348.7			$327.8		$318.2			$305.9			$301.3			$287.0
Amortization of debt premium, discount and expense (net)	3.4			4.6			4.7		9.7			5.3			4.9			4.8
Interest component on rentals	2.6			3.4			3.7		4.1			4.9			4.9			5.2
Total Fixed Charges (A)		$270.8			$356.7			$336.2		$332.0			$316.1			$311.1			$297.0
Earnings as defined:
Pretax income from continuing operations		$681.5		$822.0			$1,138.4			$786.0			$693.8			$601.6			$555.6
Total fixed charges above	270.8			356.7			336.2		332.0			316.1			311.1			297.0
Pretax equity in (earnings) losses of investees	(0.3		)	(0.1		)	0.8		(1.4		)	(3.2		)	(3.3		)	(2.9		)
Cash distributions from equity investees	2.8			3.8			4.0		7.4			9.6			3.3			3.6
Total Earnings (B)	$954.8			$1,182.4			$1,479.4		$1,124.0			$1,016.3				$912.7			$853.3
Ratio of Earnings to Fixed Charges (B/A)	3.53			3.31			4.40		3.39			3.22			2.93			2.87

SCE&G:	Nine Months Ended September 30, 2016		Twelve Months Ended September 30, 2016		Years ended December 31,
Dollars in Millions					2015		2014		2013		2012		2011
Fixed Charges as defined:
Interest on debt		$211.1		$277.9		$258.4		$237.6		$226.4		$217.4		$207.8
Amortization of debt premium, discount and expense (net)	2.7		3.5		3.7		4.4		4.2		3.9		3.9
Interest component on rentals	2.7		3.8		4.1		4.0		4.5		3.2		3.6
Total Fixed Charges (A)		$216.5		$285.2		$266.2		$246.0		$235.1		$224.5		$215.3
Earnings as defined:
Pretax income from continuing operations		$634.8		$744.9		$711.0		$676.0		$579.7		$509.5		$456.5
Total fixed charges above	216.5		285.2		266.2		246.0		235.1		224.5		215.3
Pretax equity in losses of investees	2.5		3.6		5.0		5.3		3.5		3.8		2.3
Total Earnings (B)		$853.8	$1,033.7			$982.2		$927.3		$818.3		$737.8		$674.1
Ratio of Earnings to Fixed Charges (B/A)	3.94		3.62		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: November 4, 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: November 4, 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: November 4, 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: November 4, 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 September 30, 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: November 4, 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 September 30, 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: November 4, 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	9 Months Ended
	Sep. 30, 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	Sep. 30, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding	142,916,917
SCEG
Entity Information [Line Items]
Entity Registrant Name	SOUTH CAROLINA ELECTRIC & GAS CO
Entity Central Index Key	0000091882
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding	40,296,147

XML

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Assets
Utility Plant In Service	$ 13,307	$ 12,883
Accumulated Depreciation and Amortization	(4,413)	(4,307)
Construction Work in Progress	4,584	4,051
Nuclear Fuel, Net of Accumulated Amortization	312	308
Goodwill, Net of Writedown of $230	210	210
Utility Plant, Net	14,000	13,145
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	277	280
Assets held in trust, net-nuclear decommissioning	125	115
Other investments	74	71
Nonutility Property and Investments, Net	476	466
Current Assets:
Cash and cash equivalents	56	176
Receivables, net of allowance for uncollectible accounts	530	505
Other	96	227
Income Taxes receivable	306	0
Inventories (at average cost):
Fuel	134	164
Materials and supplies	152	148
Prepaid Expense	113	115
Other current assets	66	43
Total Current Assets	1,453	1,378
Deferred Debits and Other Assets:
Regulatory Assets, Noncurrent	2,202	1,937
Other	315	220
Total Deferred Debits and Other Assets	2,517	2,157
Total	18,446	17,146
Capitalization and Liabilities
Common Stock, Value, Outstanding	2,390	2,390
Retained Earnings, Unappropriated	3,342	3,118
Accumulated Other Comprehensive Income (Loss), Net of Tax	(57)	(65)
Stockholders' Equity Attributable to Parent	5,675	5,443
Long-term Debt, Excluding Current Maturities	6,472	5,882
Total Capitalization	12,147	11,325
Current Liabilities:
Short-term borrowings	778	531
Current portion of long-term debt	117	116
Accounts payable	278	590
Customer deposits and customer prepayments	179	137
Taxes accrued	158	242
Interest accrued	92	83
Dividends declared	80	76
Derivative financial instruments	54	50
Other	128	127
Total Current Liabilities	1,864	1,952
Deferred Credits and Other Liabilities:
Deferred Income Tax Liabilities, Net	2,063	1,907
Asset retirement obligations	543	520
Pension and other postretirement benefits	327	315
Unrecognized Tax Benefits	254	44
Regulatory Liabilities	864	855
Other	384	228
Total Deferred Credits and Other Liabilities	4,435	3,869
Commitments and Contingencies
Total	18,446	17,146
SCEG
Assets
Utility Plant In Service	11,420	11,153
Accumulated Depreciation and Amortization	(3,961)	(3,869)
Construction Work in Progress	4,538	3,997
Nuclear Fuel, Net of Accumulated Amortization	312	308
Utility Plant, Net	12,309	11,589
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	68	68
Assets held in trust, net-nuclear decommissioning	125	115
Other investments	3	1
Nonutility Property and Investments, Net	196	184
Current Assets:
Cash and cash equivalents	29	130
Receivables, net of allowance for uncollectible accounts	402	324
Other	80	202
Income Taxes receivable	206
Due from Affiliate, Current	4	22
Inventories (at average cost):
Fuel	77	98
Materials and supplies	139	136
Prepaid Expense	99	92
Other current assets	48	15
Total Current Assets	1,084	1,019
Deferred Debits and Other Assets:
Regulatory Assets, Noncurrent	2,114	1,857
Other	275	116
Total Deferred Debits and Other Assets	2,389	1,973
Total	15,978	14,765
Capitalization and Liabilities
Common Stock, Value, Outstanding	2,860	2,760
Retained Earnings, Unappropriated	2,469	2,265
Accumulated Other Comprehensive Income (Loss), Net of Tax	(3)	(3)
Stockholders' Equity Attributable to Parent	5,326	5,022
Stockholders' Equity Attributable to Noncontrolling Interest	133	129
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	5,459	5,151
Long-term Debt, Excluding Current Maturities	5,153	4,659
Total Capitalization	10,612	9,810
Current Liabilities:
Short-term borrowings	714	420
Current portion of long-term debt	112	110
Accounts payable	183	469
Due to Affiliate, Current	95	113
Customer deposits and customer prepayments	131	93
Taxes accrued	148	299
Interest accrued	72	66
Dividends declared	76	75
Derivative financial instruments	48	34
Other	62	61
Total Current Liabilities	1,641	1,740
Deferred Credits and Other Liabilities:
Deferred Income Tax Liabilities, Net	1,859	1,732
Asset retirement obligations	510	488
Pension and other postretirement benefits	193	186
Unrecognized Tax Benefits	254	44
Regulatory Liabilities	630	635
Other	262	113
Other -affiliate	17	17
Total Deferred Credits and Other Liabilities	3,725	3,215
Total	$ 15,978	$ 14,765

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) shares in Millions, $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Common Stock, Shares, Outstanding	142.9	142.9
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	$ 136	$ 124
Public Utilities, Property, Plant and Equipment, Net	14,000	13,145
Allowance for Doubtful Accounts Receivable, Current	5	5
Write-down, Goodwill	230	230
Assets, Current	1,453	1,378
Regulated Entity, Other Assets, Noncurrent	$ 2,517	$ 2,157
SCEG
Common Stock, Shares, Outstanding	40.3	40.3
Public Utilities, Property, Plant and Equipment, Net	$ 12,309	$ 11,589
Allowance for Doubtful Accounts Receivable, Current	4	3
Assets, Current	1,084	1,019
Regulated Entity, Other Assets, Noncurrent	2,389	1,973
SCEG | Variable Interest Entity, Primary Beneficiary [Member]
Public Utilities, Property, Plant and Equipment, Net	695	700
Assets, Current	57	88
Regulated Entity, Other Assets, Noncurrent	$ 64	$ 53

XML

CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Operating Revenues:
Electric Domestic Regulated Revenue	$ 817	$ 742	$ 2,035	$ 2,008
Regulated Operating Revenue, Gas	111	112	538	610
Gas-nonregulated	165	214	598	805
Regulated and Unregulated Operating Revenue	1,093	1,068	3,171	3,423
Operating Expenses [Abstract]
Fuel used in electric generation	176	187	443	525
Purchased power	21	14	50	38
Gas purchased for resale	202	260	752	1,030
Other operation and maintenance	187	182	558	527
Depreciation and amortization	93	75	276	267
Other taxes	66	58	192	176
Total Operating Expenses	745	776	2,271	2,563
Gain (Loss) on Disposition of Regulated Business Net of Transaction Costs	0	0	0	235
Operating Income	348	292	900	1,095
Other Income (Expense):
Other income	15	19	46	56
Other expense	(7)	(16)	(31)	(44)
Gain (Loss) On Disposition Of Unregulated Business Net Of Transaction Costs	0	0	0	107
Interest Expense	(88)	(81)	(255)	(236)
Allowance for equity funds used during construction	7	8	22	20
Total Other Expense	(73)	(70)	(218)	(97)
Income Before Income Tax Expense	275	222	682	998
Income Tax Expense	86	73	211	350
Net Income	$ 189	$ 149	$ 471	$ 648
Earnings Per Share, Basic and Diluted	$ 1.32	$ 1.04	$ 3.29	$ 4.53
Per Common Share Data
Weighted Average Number of Shares Outstanding, Basic and Diluted	142.9	142.9	142.9	142.9
Weighted Average Common Shares Outstanding (millions)
Dividends, Common Stock			$ 247	$ 234
Common Stock, Dividends, Per Share, Declared	$ 0.575	$ 0.545	$ 1.725	$ 1.635
SCEG
Operating Revenues:
Electric Domestic Regulated Revenue	$ 818	$ 743	$ 2,039	$ 2,013
Regulated Operating Revenue, Gas	64	63	253	275
Regulated Operating Revenue	882	806	2,292	2,288
Operating Expenses [Abstract]
Fuel used in electric generation	176	187	443	525
Purchased power	21	14	50	38
Gas purchased for resale	36	37	126	151
Other operation and maintenance	152	148	454	428
Depreciation and amortization	76	59	225	220
Other taxes	62	54	178	163
Total Operating Expenses	523	499	1,476	1,525
Operating Income	359	307	816	763
Other Income (Expense):
Other income	7	6	20	24
Other expense	(4)	(7)	(19)	(21)
Interest Expense	(70)	(63)	(201)	(183)
Allowance for equity funds used during construction	6	8	19	18
Total Other Expense	(61)	(56)	(181)	(162)
Income Before Income Tax Expense	298	251	635	601
Income Tax Expense	94	84	202	196
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	204	167	433	405
Net Income (Loss) Attributable to Noncontrolling Interest	(3)	(3)	(10)	(11)
Earnings Available to Common Shareholder	201	164	423	394
Weighted Average Common Shares Outstanding (millions)
Dividends, Common Stock	$ 76	$ 71	$ 225	$ 211

XML

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Allowance for Funds Used During Construction, Capitalized Interest	$ 5	$ 5	$ 14	$ 12
SCEG
Allowance for Funds Used During Construction, Capitalized Interest	$ 5	$ 4	$ 13	$ 11

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Net Income (Loss) Attributable to Parent [Abstract]
Net Income (Loss) Available to Common Stockholders, Basic	$ 189	$ 149	$ 471	$ 648
Other Comprehensive Income (Loss)
Unrealized gains (losses) on cash flow hedging activities arising during period	(1)	(7)	(4)	(8)
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	1	(4)	8	8
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, before Reclassification Adjustments, Net of Tax	0	(1)	0	3
Other Comprehensive Income (Loss)	1	(3)	8	5
Comprehensive income available to common shareholder	190	146	479	653
SCEG
Other Comprehensive Income (Loss)
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	204	167	433	405
Genco
Other Comprehensive Income (Loss)
Less comprehensive income attributable to noncontrolling interest	3	3	10	11
SCE&G (including Fuel Company)
Net Income (Loss) Attributable to Parent [Abstract]
Net Income (Loss) Available to Common Stockholders, Basic			423	394
Other Comprehensive Income (Loss)
Comprehensive income available to common shareholder	201	164	423	394
Commodity Contract
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	0	1	6	10
Interest Rate Contract
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	2	2	6	6
Cash Flow Hedging [Member] | Interest Expense [Member] | Interest Rate Contract
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ (2)	$ (2)	$ (6)	$ (6)

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Tax	$ 0	$ 0	$ 0	$ (2)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	0	(4)	(3)	(5)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax	1	1	3	3
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income, Tax	$ 0	$ 0	$ 3	$ 6

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Cash Flows From Operating Activities:
Net Income (Loss) Available to Common Stockholders, Basic	$ 471	$ 648
Adjustments to reconcile net income to net cash provided from operating activities:
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal		(355)
Deferred Income Tax Expense (Benefit)	151	(98)
Depreciation and amortization	289	276
Amortization of nuclear fuel	42	41
Allowance for equity funds used during construction	(22)	(20)
Carrying cost recovery	(12)	(9)
Cash provided (used) by changes in certain assets and liabilities:
Increase (Decrease) in Receivables	(8)	192
Increase (Decrease) Income Taxes Receivable	(306)
Increase (Decrease) in Inventories	(21)	2
increase (Decrease) in Prepaid Expense	(2)	196
Increase (Decrease) in Other Regulatory Assets	(14)	26
Increase (Decrease) in Regulatory liabilities	2	14
Increase (Decrease ) in Accounts payable	(36)	(85)
Unrecognized tax benefits, increase (decrease)	210	2
Increase (Decrease) in Taxes accrued	(84)	2
Increase (Decrease) in Derivative Assets and Liabilities	(9)	(8)
Changes in other assets	(58)	81
Changes in other liabilities	86	(98)
Net Cash Provided From Operating Activities	679	807
Cash Flows From Investing Activities:
Property additions and construction expenditures	(1,178)	(851)
Proceeds from Sale of Property, Plant, and Equipment	0	647
Proceeds from investments (including derivative collateral posted)	629	872
Purchase of investments (including derivative collateral posted)	(743)	(872)
Payments for Hedge, Investing Activities	(88)	(152)
Proceeds from Hedge, Investing Activities		10
Net Cash Used in Investing Activities	(1,380)	(346)
Cash Flows From Financing Activities:
Proceeds from Issuance of Common Stock		14
Proceeds from Issuance of Long-term Debt	592	491
Repayments of Long-term Debt	(15)	(164)
Dividends	(243)	(231)
Short-term borrowings, net	247	(654)
Net Cash Provided From Financing Activities	581	(544)
Net (Decrease) Increase in Cash and Cash Equivalents	(120)	(83)
Cash and Cash Equivalents, January 1	176	137
Cash and Cash Equivalents, September 30	56	54
Supplemental Cash Flow Information:
Cash paid for-Interest (net of capitalized interest )	235	224
Cash paid for-Income taxes	229	184
Noncash Investing and Financing Activities:
Accrued construction expenditures	80	85
Capital Lease Obligations Incurred	12	5
SCEG
Cash Flows From Operating Activities:
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	433	405
Adjustments to reconcile net income to net cash provided from operating activities:
Deferred Income Tax Expense (Benefit)	127	(14)
Depreciation and amortization	229	221
Amortization of nuclear fuel	42	41
Allowance for equity funds used during construction	(19)	(18)
Carrying cost recovery	(12)	(9)
Cash provided (used) by changes in certain assets and liabilities:
Increase (Decrease) in Receivables	(70)	(41)
Increase (Decrease) Income Taxes Receivable	(206)
Increase (Decrease) in Due from Affiliates, Current	9	87
Increase (Decrease) in Inventories	(14)	(15)
increase (Decrease) in Prepaid Expense	(15)	63
Increase (Decrease) in Other Regulatory Assets	(6)	24
Increase (Decrease) in Regulatory liabilities	(3)	11
Increase (Decrease ) in Accounts payable	(13)	34
Unrecognized tax benefits, increase (decrease)	210	2
Increase (Decrease) in Due to Affiliate, Current	(13)	(55)
Increase (Decrease) in Taxes accrued	(151)	109
Changes in other assets	(117)	67
Changes in other liabilities	64	(110)
Net Cash Provided From Operating Activities	475	802
Cash Flows From Investing Activities:
Property additions and construction expenditures	(1,024)	(748)
Proceeds from investments (including derivative collateral posted)	577	768
Purchase of investments (including derivative collateral posted)	(699)	(776)
Investment In Affiliate	9	80
Payments for Hedge, Investing Activities	(88)	(152)
Proceeds from Hedge, Investing Activities		10
Net Cash Used in Investing Activities	(1,225)	(818)
Cash Flows From Financing Activities:
Proceeds from Issuance of Long-term Debt	494	491
Repayments of Long-term Debt	(10)	(10)
Dividends	(224)	(214)
Proceeds from Contributions from Parent	100	200
Return of Capital to Parent		(4)
Short-term borrowings-affiliate,net	(5)	(42)
Short-term borrowings, net	294	(475)
Net Cash Provided From Financing Activities	649	(54)
Net (Decrease) Increase in Cash and Cash Equivalents	(101)	(70)
Cash and Cash Equivalents, January 1	130	100
Cash and Cash Equivalents, September 30	29	30
Supplemental Cash Flow Information:
Cash paid for-Interest (net of capitalized interest )	182	169
Income Taxes Paid	286	89
Proceeds from Income Tax Refunds	9	84
Noncash Investing and Financing Activities:
Accrued construction expenditures	71	76
Capital Lease Obligations Incurred	$ 12	$ 5

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Interest Paid, Capitalized	$ 14	$ 12
SCEG
Interest Paid, Capitalized	$ 13	$ 11

XML

CONSOLIDATED STATEMENTS OF COMMON EQUITY Statement - USD ($) shares in Millions, $ in Millions	Total	AOCI Attributable to Parent [Member]	SCEG	SCEG excluding VIEs [Member]	SCEG and GENCO [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	$ 13
Stock Issued During Period, Value, Treasury Stock Reissued	$ (1)
Common Stock, Dividends, Per Share, Declared	$ 1.635
Net Income (Loss) Available to Common Stockholders, Basic	$ 648			394
Net Income (Loss) Attributable to Noncontrolling Interest			11		11
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest			405
Proceeds from Contribution from Parent, net of return of Proceeds				196
Dividends			210	205
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders					5
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	(8)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax	(3)
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	8
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	16
Other Comprehensive Income (Loss)	5
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	$ 653			394
Stock Issued During Period, Shares, New Issues	0
Proceeds from Issuance of Common Stock	$ 14
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax	0
Dividends, Common Stock	(234)		(211)
Treasury Stock, Value	(11)
Retained Earnings, Appropriated	3,098			2,266
AOCI before Tax, Attributable to Parent	(16)	$ (11)
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	(55)
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	(15)
Accumulated Other Comprehensive Income (Loss)	(70)			$ (3)
Stockholders' Equity Attributable to Noncontrolling Interest					129
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest			5,148
Stockholders' Equity Attributable to Parent	5,419
Shares, Outstanding				40
Common Stock, Value, Outstanding				$ 2,756
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	$ 1.725
Net Income (Loss) Available to Common Stockholders, Basic	$ 471			423
Net Income (Loss) Attributable to Noncontrolling Interest			10		10
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest			433
Proceeds from Contribution from Parent, net of return of Proceeds				100
Dividends			225	219
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders					6
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	(4)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax	0
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	8
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	12
Other Comprehensive Income (Loss)	8
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	479			423
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax	0
Dividends, Common Stock	(247)		(225)
Stockholders' Equity before Treasury Stock	2,402
Treasury Stock, Value	(12)
Retained Earnings, Appropriated	3,342		2,469	2,469
AOCI before Tax, Attributable to Parent	(12)	$ (4)
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	(45)
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	(12)
Accumulated Other Comprehensive Income (Loss)	(57)			$ (3)
Stockholders' Equity Attributable to Noncontrolling Interest			133		$ 133
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest			5,459
Stockholders' Equity Attributable to Parent	$ 5,675		5,326
Shares, Outstanding	143			40
Common Stock, Value, Outstanding	$ 2,390		$ 2,860	$ 2,860

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

9 Months Ended

Sep. 30, 2016

Significant Accounting Policies

Significant Accounting Policies [Text Block]

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 $483 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 4.

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, through an agency relationship, 41% and 46% of PSNC Energy’s natural gas inventory at September 30, 2016 and December 31, 2015, respectively, with a carrying value of $13.1 million and $17.7 million, respectively.  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. When applicable, 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.

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, $(100) million of non-cash changes in fair value of interest rate swaps has been reclassified from the changes in Derivative financial instruments caption (which for Consolidated SCE&G resulted in the caption being eliminated) with offsetting reclassifications of $66 million from the changes in Regulatory assets caption, $(5) million from the changes in Regulatory liabilities caption, $(6) million from the changes in Other assets caption and $45 million from the changes in Other liabilities caption. 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, and the caption of Losses from equity method investments has been eliminated and its amount included within changes in Other assets. 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 earlier revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive

in exchange for those goods or services. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018. The guidance permits adoption using a retrospective method, with options to elect certain practical expedients, or recognition of a cumulative effect in the year of initial adoption. The Company and Consolidated SCE&G have not determined which method of adoption will be employed or what practical expedients may be elected. The Company and Consolidated SCE&G have not determined the impact this guidance will have on their respective financial statements. However, the identification of implementation project team members and the analysis of contracts with customers to which the guidance might be applicable, particularly large customer contracts, have begun.

In 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 and have determined that the adoption of this guidance will not have a significant impact on their respective financial statements.

In January 2016, the FASB issued accounting guidance that will change how entities measure certain equity investments and financial liabilities, among other things. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018. The Company and Consolidated SCE&G are evaluating this guidance and do not anticipate that its adoption will have a significant impact on their respective financial statements.

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

leases. The guidance applies a right-of-use model and, for lessees, requires all leases with a duration over 12 months to be

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

and without consideration of any regulatory accounting requirements which may apply, depending primarily on the nature of the assets and the relative consumption of them, lease costs will be recognized either through the separate amortization of the right-of-use asset and the recognition of the interest cost related to the payment obligation, or through the recording of a combined straight-line rental expense. For lessors, the guidance calls for the recognition of income either through the derecognition of assets and subsequent recording of interest income on lease amounts receivable, or through the recognition of rental income on a straight-line basis, also depending on the nature of the assets and relative consumption. The guidance will be effective for years beginning in 2019. The Company and Consolidated SCE&G have not determined what impact this guidance will have on their respective financial statements. However, the identification of implementation project team members and the initial identification and analysis of leasing and related contracts to which the guidance might be applicable have begun.

In 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, based on the nature of their current share-based awards practices, do not anticipate that its adoption will have a significant impact on their respective financial statements.

In June 2016, the FASB issued accounting guidance requiring the use of a current expected credit loss impairment model for certain financial instruments. The new model is applicable to trade receivables and most debt instruments, among other financial instruments, and is intended to result in impairment losses being recognized earlier than under current guidance. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted in 2019. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective financial statements.

In August 2016, the FASB issued accounting guidance to reduce diversity in cash flow classification related to certain transactions. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018 and do not anticipate that its adoption will impact their respective financial statements.

SCEG

Significant Accounting Policies

Significant Accounting Policies [Text Block]

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 $483 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 4.

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, through an agency relationship, 41% and 46% of PSNC Energy’s natural gas inventory at September 30, 2016 and December 31, 2015, respectively, with a carrying value of $13.1 million and $17.7 million, respectively.  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. When applicable, 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.

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, $(100) million of non-cash changes in fair value of interest rate swaps has been reclassified from the changes in Derivative financial instruments caption (which for Consolidated SCE&G resulted in the caption being eliminated) with offsetting reclassifications of $66 million from the changes in Regulatory assets caption, $(5) million from the changes in Regulatory liabilities caption, $(6) million from the changes in Other assets caption and $45 million from the changes in Other liabilities caption. 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, and the caption of Losses from equity method investments has been eliminated and its amount included within changes in Other assets. 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 earlier revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive

in exchange for those goods or services. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018. The guidance permits adoption using a retrospective method, with options to elect certain practical expedients, or recognition of a cumulative effect in the year of initial adoption. The Company and Consolidated SCE&G have not determined which method of adoption will be employed or what practical expedients may be elected. The Company and Consolidated SCE&G have not determined the impact this guidance will have on their respective financial statements. However, the identification of implementation project team members and the analysis of contracts with customers to which the guidance might be applicable, particularly large customer contracts, have begun.

In 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 and have determined that the adoption of this guidance will not have a significant impact on their respective financial statements.

In January 2016, the FASB issued accounting guidance that will change how entities measure certain equity investments and financial liabilities, among other things. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018. The Company and Consolidated SCE&G are evaluating this guidance and do not anticipate that its adoption will have a significant impact on their respective financial statements.

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

leases. The guidance applies a right-of-use model and, for lessees, requires all leases with a duration over 12 months to be

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

and without consideration of any regulatory accounting requirements which may apply, depending primarily on the nature of the assets and the relative consumption of them, lease costs will be recognized either through the separate amortization of the right-of-use asset and the recognition of the interest cost related to the payment obligation, or through the recording of a combined straight-line rental expense. For lessors, the guidance calls for the recognition of income either through the derecognition of assets and subsequent recording of interest income on lease amounts receivable, or through the recognition of rental income on a straight-line basis, also depending on the nature of the assets and relative consumption. The guidance will be effective for years beginning in 2019. The Company and Consolidated SCE&G have not determined what impact this guidance will have on their respective financial statements. However, the identification of implementation project team members and the initial identification and analysis of leasing and related contracts to which the guidance might be applicable have begun.

In 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, based on the nature of their current share-based awards practices, do not anticipate that its adoption will have a significant impact on their respective financial statements.

In June 2016, the FASB issued accounting guidance requiring the use of a current expected credit loss impairment model for certain financial instruments. The new model is applicable to trade receivables and most debt instruments, among other financial instruments, and is intended to result in impairment losses being recognized earlier than under current guidance. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted in 2019. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective financial statements.

In August 2016, the FASB issued accounting guidance to reduce diversity in cash flow classification related to certain transactions. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018 and do not anticipate that its adoption will impact their respective financial statements.

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RATE AND OTHER REGULATORY MATTERS

9 Months Ended

Sep. 30, 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, ORS and certain other parties concerning SCE&G's petition for approval to participate in a DER program and to recover DER program costs as a separate component of SCE&G's overall fuel factor. Under this order, SCE&G will, among other things, implement programs to encourage the development of renewable energy facilities with a total nameplate capacity of at least approximately 84.5 MW by the end of 2020, of which half is to be customer-scale solar capacity and half is to be utility-scale solar capacity.

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

Electric - Base Rates

Pursuant to an SCPSC order, SCE&G removes from rate base certain deferred income tax assets arising from capital expenditures related to the New Units and accrues carrying costs on those amounts during periods in which they are not included in rate base.  Such carrying costs are determined at SCE&G’s weighted average long-term debt borrowing rate and are recorded as a regulatory asset and other income. Carrying costs during the three and nine months ended September 30, 2016 totaled $3.5 million and $10.0 million, respectively. During the three and nine months ended September 30, 2015, carrying costs totaled $2.4 million and $6.5 million, respectively. SCE&G anticipates that when the New Units are placed in service and accelerated tax depreciation is recognized on them, these deferred income tax assets will decline. When these 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 rider. Under the terms of the order, SCE&G may request an annual adjustment to the pension rider. The increased pension rider is designed to allow SCE&G to recover projected pension costs, including under-collections, over a 12-month period, beginning with the first billing cycle in May 2016.

In 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. 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 along with a shared savings incentive associated with the DSM Programs.

Electric - BLRA

On May 26, 2016, SCE&G petitioned the SCPSC seeking approval to update the capital cost schedule and construction milestone schedule for the New Units consistent with the October 2015 Amendment. Within this petition, SCE&G also informed the SCPSC that it had notified WEC of its intent to elect the fixed price option, subject to concurrence by Santee Cooper and approval by the SCPSC. The petition reflects an increase in total project costs of approximately $852 million over the cost approved by the SCPSC in September 2015, of which approximately $505 million is directly attributable to the fixed price option. On July 1, 2016, SCE&G reduced the total project cost amount set forth in its petition to $846 million. SCE&G's estimated gross construction cost for the project is now estimated to be approximately $7.7 billion, including owner’s costs, transmission, escalation and AFC. SCE&G executed the fixed price option on July 1, 2016, for itself and on behalf of Santee Cooper, subject to SCPSC approval.

On September 1, 2016, SCE&G, ORS and certain other parties entered into a settlement agreement related to SCE&G’s May 26, 2016 petition to update construction and capital cost schedules, including SCE&G’s election of the fixed price option included in the October 2015 Amendment. Under the terms of the settlement agreement, the settling parties agree to support SCPSC approval of the updated construction schedule, which indicates substantial completion dates of August 2019 and August 2020 for the New Units, and SCE&G’s election of the fixed price option. In addition, the settling parties agree to the inclusion of an additional $831 million in the capital cost schedule and to revise the allowed ROE for the New Units from 10.50% to 10.25%. The revised ROE will be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2017, until such time as the New Units are completed. Also, pursuant to the settlement agreement, SCE&G agreed not to file any future requests to amend its capital cost schedule prior to January 28, 2019. For those capital costs which were included in the total project amount set forth in SCE&G’s petition but not included in the capital cost schedule as agreed upon by the settling parties, SCE&G may seek to include those costs in its calculation of revised rates after January 2019. The settlement agreement is subject to SCPSC approval. A public hearing on this matter was held in October 2016, and the SCPSC is expected to issue its order in November 2016.  See also Note 9.

On October 19, 2016, the SCPSC approved an increase of approximately $64.4 million, or 2.7%, in SCE&G's retail electric rates under provisions of the BLRA. The rate increase is effective for the first billing cycle on or after November 27, 2016.

Gas - SCE&G

By order dated October 13, 2016, the SCPSC approved SCE&G's quarterly monitoring report for the 12-month period ended March 31, 2016, and an approximately $4.1 million, or 1.2%, overall increase to its natural gas rates under the terms of the RSA. The rate adjustment will be effective for the first billing cycle in November 2016.

SCE&G's natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred, including transportation costs. SCE&G's gas rates are calculated using a methodology which may adjust the cost of gas monthly based on a 12-month rolling average, and its gas purchasing policies and practices are reviewed annually by the SCPSC. SCE&G's annual PGA hearing for the 12-month period ending July 31, 2016, was held on November 3, 2016, and the SCPSC's decision is pending.

Gas - PSNC Energy

On October 28, 2016, the NCUC granted PSNC Energy a net annual increase of approximately $19.1 million, or 4.39%, in rates and charges to customers, and set PSNC Energy's authorized ROE at 9.7%. The rate increase is largely associated with recovering costs related to expanding and operating PSNC Energy's pipeline system. In addition, PSNC Energy was authorized to implement a tracker that provides for biannual rate adjustments in order to recover the revenue requirement associated with integrity management plant investment and associated costs incurred by PSNC Energy resulting from prevailing federal standards for pipeline integrity and safety that are not otherwise included in current base rates.  The new rates are effective for services rendered on or after November 1, 2016.

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	September 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
Regulatory Assets:
Accumulated deferred income taxes	$	301	$	298	$	294	$	291
Environmental remediation costs	33		42		26		35
AROs and related funding	402		405		380		384
Deferred employee benefit plan costs	311		325		282		295
Deferred losses on interest rate derivatives	791		535		791		535
Unrecovered plant	119		127		119		127
DSM Programs	58		61		58		61
Deferred costs related to uncertain tax position	14		—		14		—
Other	173		144		150		129
Total Regulatory Assets	$	2,202	$	1,937	$	2,114	$	1,857

Regulatory Liabilities:
Asset removal costs	$	756	$	732	$	533	$	519
Deferred gains on interest rate derivatives	80		96		80		96
Other	28		27		17		20
Total Regulatory Liabilities	$	864	$	855	$	630	$	635

Accumulated deferred income tax liabilities that arise from utility operations that have not been included in customer rates are recorded as a regulatory asset.  A substantial portion of these regulatory assets relate to depreciation and are expected to be recovered over the remaining lives of the related property which may range up to approximately 85 years.  Similarly, accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability.

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 18 years.

AROs and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station and conditional AROs related to generation, transmission and distribution properties, including gas pipelines. These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 110 years.

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

Deferred costs related to uncertain tax position primarily represent the estimated amounts of domestic production activities deductions foregone as a result of the Company’s deduction of certain research and experimentation expenditures for income tax purposes, net of related tax credits, as well as accrued interest expense and other costs arising from this unrecognized tax benefit. SCE&G's current customer rates reflect the availability of domestic production activities deductions. These net deferred costs are expected to be recovered through utility rates following ultimate resolution of the claims. See also Note 5.

Various other regulatory assets are expected to be recovered 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, ORS and certain other parties concerning SCE&G's petition for approval to participate in a DER program and to recover DER program costs as a separate component of SCE&G's overall fuel factor. Under this order, SCE&G will, among other things, implement programs to encourage the development of renewable energy facilities with a total nameplate capacity of at least approximately 84.5 MW by the end of 2020, of which half is to be customer-scale solar capacity and half is to be utility-scale solar capacity.

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

Electric - Base Rates

Pursuant to an SCPSC order, SCE&G removes from rate base certain deferred income tax assets arising from capital expenditures related to the New Units and accrues carrying costs on those amounts during periods in which they are not included in rate base.  Such carrying costs are determined at SCE&G’s weighted average long-term debt borrowing rate and are recorded as a regulatory asset and other income. Carrying costs during the three and nine months ended September 30, 2016 totaled $3.5 million and $10.0 million, respectively. During the three and nine months ended September 30, 2015, carrying costs totaled $2.4 million and $6.5 million, respectively. SCE&G anticipates that when the New Units are placed in service and accelerated tax depreciation is recognized on them, these deferred income tax assets will decline. When these 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 rider. Under the terms of the order, SCE&G may request an annual adjustment to the pension rider. The increased pension rider is designed to allow SCE&G to recover projected pension costs, including under-collections, over a 12-month period, beginning with the first billing cycle in May 2016.

In 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. 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 along with a shared savings incentive associated with the DSM Programs.

Electric - BLRA

On May 26, 2016, SCE&G petitioned the SCPSC seeking approval to update the capital cost schedule and construction milestone schedule for the New Units consistent with the October 2015 Amendment. Within this petition, SCE&G also informed the SCPSC that it had notified WEC of its intent to elect the fixed price option, subject to concurrence by Santee Cooper and approval by the SCPSC. The petition reflects an increase in total project costs of approximately $852 million over the cost approved by the SCPSC in September 2015, of which approximately $505 million is directly attributable to the fixed price option. On July 1, 2016, SCE&G reduced the total project cost amount set forth in its petition to $846 million. SCE&G's estimated gross construction cost for the project is now estimated to be approximately $7.7 billion, including owner’s costs, transmission, escalation and AFC. SCE&G executed the fixed price option on July 1, 2016, for itself and on behalf of Santee Cooper, subject to SCPSC approval.

On September 1, 2016, SCE&G, ORS and certain other parties entered into a settlement agreement related to SCE&G’s May 26, 2016 petition to update construction and capital cost schedules, including SCE&G’s election of the fixed price option included in the October 2015 Amendment. Under the terms of the settlement agreement, the settling parties agree to support SCPSC approval of the updated construction schedule, which indicates substantial completion dates of August 2019 and August 2020 for the New Units, and SCE&G’s election of the fixed price option. In addition, the settling parties agree to the inclusion of an additional $831 million in the capital cost schedule and to revise the allowed ROE for the New Units from 10.50% to 10.25%. The revised ROE will be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2017, until such time as the New Units are completed. Also, pursuant to the settlement agreement, SCE&G agreed not to file any future requests to amend its capital cost schedule prior to January 28, 2019. For those capital costs which were included in the total project amount set forth in SCE&G’s petition but not included in the capital cost schedule as agreed upon by the settling parties, SCE&G may seek to include those costs in its calculation of revised rates after January 2019. The settlement agreement is subject to SCPSC approval. A public hearing on this matter was held in October 2016, and the SCPSC is expected to issue its order in November 2016.  See also Note 9.

On October 19, 2016, the SCPSC approved an increase of approximately $64.4 million, or 2.7%, in SCE&G's retail electric rates under provisions of the BLRA. The rate increase is effective for the first billing cycle on or after November 27, 2016.

Gas - SCE&G

By order dated October 13, 2016, the SCPSC approved SCE&G's quarterly monitoring report for the 12-month period ended March 31, 2016, and an approximately $4.1 million, or 1.2%, overall increase to its natural gas rates under the terms of the RSA. The rate adjustment will be effective for the first billing cycle in November 2016.

SCE&G's natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred, including transportation costs. SCE&G's gas rates are calculated using a methodology which may adjust the cost of gas monthly based on a 12-month rolling average, and its gas purchasing policies and practices are reviewed annually by the SCPSC. SCE&G's annual PGA hearing for the 12-month period ending July 31, 2016, was held on November 3, 2016, and the SCPSC's decision is pending.

Gas - PSNC Energy

On October 28, 2016, the NCUC granted PSNC Energy a net annual increase of approximately $19.1 million, or 4.39%, in rates and charges to customers, and set PSNC Energy's authorized ROE at 9.7%. The rate increase is largely associated with recovering costs related to expanding and operating PSNC Energy's pipeline system. In addition, PSNC Energy was authorized to implement a tracker that provides for biannual rate adjustments in order to recover the revenue requirement associated with integrity management plant investment and associated costs incurred by PSNC Energy resulting from prevailing federal standards for pipeline integrity and safety that are not otherwise included in current base rates.  The new rates are effective for services rendered on or after November 1, 2016.

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	September 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
Regulatory Assets:
Accumulated deferred income taxes	$	301	$	298	$	294	$	291
Environmental remediation costs	33		42		26		35
AROs and related funding	402		405		380		384
Deferred employee benefit plan costs	311		325		282		295
Deferred losses on interest rate derivatives	791		535		791		535
Unrecovered plant	119		127		119		127
DSM Programs	58		61		58		61
Deferred costs related to uncertain tax position	14		—		14		—
Other	173		144		150		129
Total Regulatory Assets	$	2,202	$	1,937	$	2,114	$	1,857

Regulatory Liabilities:
Asset removal costs	$	756	$	732	$	533	$	519
Deferred gains on interest rate derivatives	80		96		80		96
Other	28		27		17		20
Total Regulatory Liabilities	$	864	$	855	$	630	$	635

Accumulated deferred income tax liabilities that arise from utility operations that have not been included in customer rates are recorded as a regulatory asset.  A substantial portion of these regulatory assets relate to depreciation and are expected to be recovered over the remaining lives of the related property which may range up to approximately 85 years.  Similarly, accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability.

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 18 years.

AROs and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station and conditional AROs related to generation, transmission and distribution properties, including gas pipelines. These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 110 years.

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

Deferred costs related to uncertain tax position primarily represent the estimated amounts of domestic production activities deductions foregone as a result of the Company’s deduction of certain research and experimentation expenditures for income tax purposes, net of related tax credits, as well as accrued interest expense and other costs arising from this unrecognized tax benefit. SCE&G's current customer rates reflect the availability of domestic production activities deductions. These net deferred costs are expected to be recovered through utility rates following ultimate resolution of the claims. See also Note 5.

Various other regulatory assets are expected to be recovered 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

9 Months Ended

Sep. 30, 2016

Common Equity Note [Line Items]

Stockholders' Equity Note Disclosure [Text Block]

SCANA had 200 million shares of common stock authorized as of September 30, 2016 and December 31, 2015. Gains and losses on cash flow hedges reclassified from AOCI during the nine months ended September 30, 2016 resulted in higher interest expense of $6 million and higher cost of gas purchased for resale of $6 million. Such reclassifications during the comparable period in 2015 resulted in higher interest expense of $6 million and higher cost of gas purchased for resale of $10 million.

SCEG

Common Equity Note [Line Items]

Stockholders' Equity Note Disclosure [Text Block]

Authorized shares of SCE&G common stock were 50 million as of September 30, 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 September 30, 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

9 Months Ended

Sep. 30, 2016

Debt Instrument [Line Items]

Long-term Debt [Text Block]

LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

On November 1, 2016, Consolidated SCE&G paid at maturity $100 million related to a nuclear fuel financing which had an imputed interest rate of 0.78%.

In June 2016, SCE&G issued $425 million of 4.1% first mortgage bonds due June 15, 2046. In addition, SCE&G issued $75 million of 4.5% first mortgage bonds due June 1, 2064, which constituted a reopening of $300 million of 4.5% first mortgage bonds issued in May 2014. Proceeds from these sales were used to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes.

In June 2016, PSNC Energy issued $100 million of 4.13% senior notes due June 22, 2046. Proceeds from this sale were used to repay short-term debt, to finance capital expenditures, and for general corporate purposes.

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: 

	September 30, 2016
Millions of dollars	Total		SCANA			Consolidated SCE&G			PSNC  Energy
Lines of credit:
Five-year, expiring December 2020	$	1,300.0	$	400.0		$	700.0		$	200.0
Fuel Company five-year, expiring December 2020	$	500.0	—			$	500.0		—
Three-year, expiring December 2018	$	200.0	—			$	200.0		—
Total committed long-term	$	2,000.0	$	400.0		$	1,400.0		$	200.0
Outstanding commercial paper (270 or fewer days)	$	777.6	$	16.0		$	714.2		$	47.4
Weighted average interest rate			0.93		%	0.84		%	0.83		%
Letters of credit supported by LOC	$	3.3	$	3.0		$	0.3		—
Available	$	1,219.1	$	381.0		$	685.5		$	152.6

	December 31, 2015
Millions of dollars	Total		SCANA			Consolidated SCE&G			PSNC  Energy
Lines of credit:
Five-year, expiring December 2020	$	1,300.0	$	400.0		$	700.0		$	200.0
Fuel Company five-year, expiring December 2020	$	500.0	—			$	500.0		—
Three-year, expiring December 2018	$	200.0	—			$	200.0		—
Total committed long-term	$	2,000.0	$	400.0		$	1,400.0		$	200.0
Outstanding commercial paper (270 or fewer days)	$	531.4	$	37.4		$	420.2		$	73.8
Weighted average interest rate			1.19		%	0.74		%	0.77		%
Letters of credit supported by LOC	$	3.3	$	3.0		$	0.3		—
Available	$	1,465.4	$	359.6		$	979.6		$	126.2

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 September 30, 2016, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $28.1 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 its balance sheet, Consolidated SCE&G includes amounts due from an affiliate within Receivables-affiliated companies and amounts due to an affiliate within Affiliated payables.

SCEG

Debt Instrument [Line Items]

Long-term Debt [Text Block]

LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

On November 1, 2016, Consolidated SCE&G paid at maturity $100 million related to a nuclear fuel financing which had an imputed interest rate of 0.78%.

In June 2016, SCE&G issued $425 million of 4.1% first mortgage bonds due June 15, 2046. In addition, SCE&G issued $75 million of 4.5% first mortgage bonds due June 1, 2064, which constituted a reopening of $300 million of 4.5% first mortgage bonds issued in May 2014. Proceeds from these sales were used to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes.

In June 2016, PSNC Energy issued $100 million of 4.13% senior notes due June 22, 2046. Proceeds from this sale were used to repay short-term debt, to finance capital expenditures, and for general corporate purposes.

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: 

	September 30, 2016
Millions of dollars	Total		SCANA			Consolidated SCE&G			PSNC  Energy
Lines of credit:
Five-year, expiring December 2020	$	1,300.0	$	400.0		$	700.0		$	200.0
Fuel Company five-year, expiring December 2020	$	500.0	—			$	500.0		—
Three-year, expiring December 2018	$	200.0	—			$	200.0		—
Total committed long-term	$	2,000.0	$	400.0		$	1,400.0		$	200.0
Outstanding commercial paper (270 or fewer days)	$	777.6	$	16.0		$	714.2		$	47.4
Weighted average interest rate			0.93		%	0.84		%	0.83		%
Letters of credit supported by LOC	$	3.3	$	3.0		$	0.3		—
Available	$	1,219.1	$	381.0		$	685.5		$	152.6

	December 31, 2015
Millions of dollars	Total		SCANA			Consolidated SCE&G			PSNC  Energy
Lines of credit:
Five-year, expiring December 2020	$	1,300.0	$	400.0		$	700.0		$	200.0
Fuel Company five-year, expiring December 2020	$	500.0	—			$	500.0		—
Three-year, expiring December 2018	$	200.0	—			$	200.0		—
Total committed long-term	$	2,000.0	$	400.0		$	1,400.0		$	200.0
Outstanding commercial paper (270 or fewer days)	$	531.4	$	37.4		$	420.2		$	73.8
Weighted average interest rate			1.19		%	0.74		%	0.77		%
Letters of credit supported by LOC	$	3.3	$	3.0		$	0.3		—
Available	$	1,465.4	$	359.6		$	979.6		$	126.2

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 September 30, 2016, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $28.1 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 its balance sheet, Consolidated SCE&G includes amounts due from an affiliate within Receivables-affiliated companies and amounts due to an affiliate within Affiliated payables.

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INCOME TAXES

9 Months Ended

Sep. 30, 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 income tax returns to claim certain tax-defined research and experimentation deductions and credits and to reflect related impacts on other items such as domestic production activities deductions. SCANA also made similar claims in filing its original 2013 and 2014 returns in 2014 and 2015, respectively.  In September 2016, SCANA claimed significant research and experimentation deductions and credits (offset by reductions in its domestic production activities deductions), related to the ongoing design and construction activities of the New Units, in its 2015 income tax returns. These claims followed the issuance of final IRS regulations in 2014 regarding such treatment with respect to expenditures related to the design and construction of pilot models. 

The IRS examined the claims in the amended returns, and as such examination of claims progressed without resolution, the Company and Consolidated SCE&G evaluated and recorded adjustments to unrecognized tax benefits; however, none of these changes materially affected the Company's and Consolidated SCE&G's effective tax rate. In October 2016, the examination of the amended tax returns progressed to appeals. In addition, the IRS has begun an examination of SCANA's 2013 through 2015 income tax returns.

These income tax deductions and credits are considered to be uncertain tax positions, and under relevant accounting guidance, estimates of the amounts of related tax benefits which may not be sustained upon examination by the taxing authorities are required to be recorded as unrecognized tax benefits in the financial statements. In connection with all of these federal and related state filings, the Company and Consolidated SCE&G have recorded an unrecognized tax benefit of $276 million ($254 million, net of the impact of the state deduction on the federal return). If recognized, $17 million of the tax benefit would affect the Company’s and Consolidated SCE&G's effective tax rate (see discussion below regarding deferral of benefits related to 2015 forward). It is reasonably possible that these unrecognized tax benefits may increase by an additional $228 million within the next 12 months as additional expenditures giving rise to tax benefits are incurred. It is also reasonably possible that these unrecognized tax benefits may decrease by $49 million within the next 12 months if the claims on amended returns which are currently in appeals are resolved. No other material changes in the status of the Company’s or Consolidated SCE&G's tax positions have occurred through September 30, 2016.

In connection with the research and experimentation deduction and credit claims reflected on the 2015 income tax returns and the expectation of similar claims to be made in determining 2016’s taxable income, the Company and Consolidated SCE&G have recorded regulatory assets for estimated foregone domestic production activities deductions, offset by estimated credits, and expect that such (net) deferred costs, along with any interest (see below) and other related deferred costs, will be recoverable through customer rates in future years. SCE&G's current customer rates reflect the availability of domestic production activities deductions (see Note 2).

Estimated interest expense accrued with respect to the unrecognized tax benefits related to the research and experimentation deductions in the 2015 income tax returns has been deferred as a regulatory asset and is expected to be recoverable through customer rates in future years. See also Note 2. Otherwise, the Company and Consolidated SCE&G recognize interest accrued related to unrecognized tax benefits within interest expense or interest income and recognize tax penalties within other expenses.  Amounts recorded for such interest income, interest expense or tax penalties have not been material.

On August 2, 2016, the State of North Carolina announced the lowering of its corporate income tax rate from 4% to 3% effective January 1, 2017. This reduction did not have a material impact on the Company's financial position, results of operations or cash flows.

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 income tax returns to claim certain tax-defined research and experimentation deductions and credits and to reflect related impacts on other items such as domestic production activities deductions. SCANA also made similar claims in filing its original 2013 and 2014 returns in 2014 and 2015, respectively.  In September 2016, SCANA claimed significant research and experimentation deductions and credits (offset by reductions in its domestic production activities deductions), related to the ongoing design and construction activities of the New Units, in its 2015 income tax returns. These claims followed the issuance of final IRS regulations in 2014 regarding such treatment with respect to expenditures related to the design and construction of pilot models. 

The IRS examined the claims in the amended returns, and as such examination of claims progressed without resolution, the Company and Consolidated SCE&G evaluated and recorded adjustments to unrecognized tax benefits; however, none of these changes materially affected the Company's and Consolidated SCE&G's effective tax rate. In October 2016, the examination of the amended tax returns progressed to appeals. In addition, the IRS has begun an examination of SCANA's 2013 through 2015 income tax returns.

These income tax deductions and credits are considered to be uncertain tax positions, and under relevant accounting guidance, estimates of the amounts of related tax benefits which may not be sustained upon examination by the taxing authorities are required to be recorded as unrecognized tax benefits in the financial statements. In connection with all of these federal and related state filings, the Company and Consolidated SCE&G have recorded an unrecognized tax benefit of $276 million ($254 million, net of the impact of the state deduction on the federal return). If recognized, $17 million of the tax benefit would affect the Company’s and Consolidated SCE&G's effective tax rate (see discussion below regarding deferral of benefits related to 2015 forward). It is reasonably possible that these unrecognized tax benefits may increase by an additional $228 million within the next 12 months as additional expenditures giving rise to tax benefits are incurred. It is also reasonably possible that these unrecognized tax benefits may decrease by $49 million within the next 12 months if the claims on amended returns which are currently in appeals are resolved. No other material changes in the status of the Company’s or Consolidated SCE&G's tax positions have occurred through September 30, 2016.

In connection with the research and experimentation deduction and credit claims reflected on the 2015 income tax returns and the expectation of similar claims to be made in determining 2016’s taxable income, the Company and Consolidated SCE&G have recorded regulatory assets for estimated foregone domestic production activities deductions, offset by estimated credits, and expect that such (net) deferred costs, along with any interest (see below) and other related deferred costs, will be recoverable through customer rates in future years. SCE&G's current customer rates reflect the availability of domestic production activities deductions (see Note 2).

Estimated interest expense accrued with respect to the unrecognized tax benefits related to the research and experimentation deductions in the 2015 income tax returns has been deferred as a regulatory asset and is expected to be recoverable through customer rates in future years. See also Note 2. Otherwise, the Company and Consolidated SCE&G recognize interest accrued related to unrecognized tax benefits within interest expense or interest income and recognize tax penalties within other expenses.  Amounts recorded for such interest income, interest expense or tax penalties have not been material.

On August 2, 2016, the State of North Carolina announced the lowering of its corporate income tax rate from 4% to 3% effective January 1, 2017. This reduction did not have a material impact on the Company's financial position, results of operations or cash flows.

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DERIVATIVE FINANCIAL INSTRUMENTS

9 Months Ended

Sep. 30, 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 in which swaps designated as cash flow hedges are used to synthetically convert variable rate debt to fixed rate debt, periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense.

Forward starting swap agreements that are designated as cash flow hedges may be used in anticipation of the issuance of debt.  Except as described in the following paragraph, the effective portions of changes in fair value and payments made or received upon termination of such agreements for regulated subsidiaries are recorded in regulatory assets or regulatory liabilities. For SCANA and 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 related to them are recorded as regulatory assets and liabilities. Settlement losses on swaps will be amortized over the lives of subsequent debt issuances and gains may be 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 September 30, 2016
Commodity contracts	8,600,000	11,781,000	4,223,500	24,604,500
Energy management contracts (a)	—	—	35,795,914	35,795,914
Total (a)	8,600,000	11,781,000	40,019,414	60,400,414
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 1,028,115 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	September 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
Designated as hedging instruments	$	115.6	$	120.0	$	36.4	$	36.4
Not designated as hedging instruments	1,285.0		1,235.0		1,285.0		1,235.0

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

Fair Values of Derivative Instruments
		The Company				Consolidated SCE&G
Millions of dollars	Balance Sheet Location	Asset		Liability		Asset		Liability
As of September 30, 2016
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	3			$	1
	Other deferred credits and other liabilities			39				14
Commodity contracts
	Other current assets	$	3	1
Total		$	3	$	43	—		$	15
Not designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	47			$	47
	Other deferred credits and other liabilities			172				172
Commodity contracts
	Other current assets	$	3
Energy management contracts
	Other current assets	4
	Other deferred debits and other assets	2
	Derivative financial instruments			4
	Other deferred credits and other liabilities			2
Total		$	9	$	225	—		$	219
As of December 31, 2015
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	4			$	1
	Other deferred credits and other liabilities			28				9
Commodity contracts
	Other current assets			1
	Derivative financial instruments			4
Total		—		$	37	—		$	10
Not designated as hedging instruments
Interest rate contracts
	Other current assets	$	10			$	10
	Other deferred debits and other assets	5				5
	Derivative financial instruments			$	33			$	33
	Other deferred credits and other liabilities			22				22
Commodity contracts
	Other current assets	1
Energy management contracts
	Other current assets	11		2
	Other deferred debits and other assets	3
	Derivative financial instruments			9
	Other deferred credits and other liabilities			3
Total		$	30	$	69	$	15	$	55

 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 September 30,
Interest rate contracts	$	(1	)	$	(3	)	Interest expense	$	(1	)	$	(1	)
Nine Months Ended September 30,
Interest rate contracts	$	(6	)	$	(3	)	Interest expense	$	(2	)	$	(2	)

The Company:
	Gain (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 September 30,
Interest rate contracts	$	1		$	(3	)	Interest expense	$	(2	)	$	(2	)
Commodity contracts	(2		)	(4		)	Gas purchased for resale	—			(1		)
Total	$	(1	)	$	(7	)		$	(2	)	$	(3	)
Nine Months Ended September 30,
Interest rate contracts	$	(4	)	$	(3	)	Interest expense	$	(6	)	$	(6	)
Commodity contracts	—			(5		)	Gas purchased for resale	(6		)	(10		)
Total	$	(4	)	$	(8	)		$	(12	)	$	(16	)

As of September 30, 2016, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $1.7 million as a decrease to gas cost, assuming natural gas markets remain at their current levels, and approximately $6.6 million as an increase to interest expense.  As of September 30, 2016, all of the Company’s commodity cash flow hedges settle by their terms before the end of the third quarter of 2019.

As of September 30, 2016, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $1.9 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 (Loss) Reclassified from Deferred Accounts into Income
Millions of dollars	2016			2015			Location	2016			2015
Three Months Ended September 30,
Interest rate contracts	$	(24	)	$	(116	)	Other income	$	(1	)	—
Nine Months Ended September 30,
Interest rate contracts	$	(268	)	$	(79	)	Other income	$	(1	)	$	5

As of September 30, 2016, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from derivatives not designated as hedges will include $2.3 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	September 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
in Net Liability Position
Aggregate fair value of derivatives in net liability position	$	263.3	$	95.2	$	234.2	$	57.0
Fair value of collateral already posted	171.5		50.4		140.4		13.4
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	91.8		44.8		93.8		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 $6.0 million in commodity derivatives that are in a net asset position at September 30, 2016, compared to letters of credit in the amount 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 and derivative liabilities 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 September 30, 2016
Gross Amounts of Recognized Assets				$	6		$	6		$	12
Gross Amounts Offset in Statement of Financial Position				(1		)	(1		)	(2		)
Net Amounts Presented in Statement of Financial Position	—			5			5			10			—
Gross Amounts Not Offset - Financial Instruments										—
Gross Amounts Not Offset - Cash Collateral Received										—
Net Amount	—			$	5		$	5		$	10		—
Balance sheet location
Other current assets										$	8
Other deferred debits and other assets										2
Total										$	10		—
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

Derivative Liabilities	The Company												Consolidated SCE&G
Millions of dollars	Interest Rate Contracts			Commodity Contracts			Energy Management Contracts			Total			Interest Rate Contracts
As of September 30, 2016
Gross Amounts of Recognized Liabilities	$	261		$	1		$	6		$	268		$	234
Gross Amounts Offset in Statement of Financial Position				(1		)	(1		)	(2		)
Net Amounts Presented in Statement of Financial Position	261			—			5			266			234
Gross Amounts Not Offset - Financial Instruments										—
Gross Amounts Not Offset - Cash Collateral Posted	(169		)				(2		)	(171		)	(140		)
Net Amount	$	92		$	—		$	3		$	95		$	94
Balance sheet location
Derivative financial instruments										$	53		$	48
Other deferred credits and other liabilities										213			186
Total										$	266		$	234
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 in which swaps designated as cash flow hedges are used to synthetically convert variable rate debt to fixed rate debt, periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense.

Forward starting swap agreements that are designated as cash flow hedges may be used in anticipation of the issuance of debt.  Except as described in the following paragraph, the effective portions of changes in fair value and payments made or received upon termination of such agreements for regulated subsidiaries are recorded in regulatory assets or regulatory liabilities. For SCANA and 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 related to them are recorded as regulatory assets and liabilities. Settlement losses on swaps will be amortized over the lives of subsequent debt issuances and gains may be 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 September 30, 2016
Commodity contracts	8,600,000	11,781,000	4,223,500	24,604,500
Energy management contracts (a)	—	—	35,795,914	35,795,914
Total (a)	8,600,000	11,781,000	40,019,414	60,400,414
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 1,028,115 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	September 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
Designated as hedging instruments	$	115.6	$	120.0	$	36.4	$	36.4
Not designated as hedging instruments	1,285.0		1,235.0		1,285.0		1,235.0

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

Fair Values of Derivative Instruments
		The Company				Consolidated SCE&G
Millions of dollars	Balance Sheet Location	Asset		Liability		Asset		Liability
As of September 30, 2016
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	3			$	1
	Other deferred credits and other liabilities			39				14
Commodity contracts
	Other current assets	$	3	1
Total		$	3	$	43	—		$	15
Not designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	47			$	47
	Other deferred credits and other liabilities			172				172
Commodity contracts
	Other current assets	$	3
Energy management contracts
	Other current assets	4
	Other deferred debits and other assets	2
	Derivative financial instruments			4
	Other deferred credits and other liabilities			2
Total		$	9	$	225	—		$	219
As of December 31, 2015
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	4			$	1
	Other deferred credits and other liabilities			28				9
Commodity contracts
	Other current assets			1
	Derivative financial instruments			4
Total		—		$	37	—		$	10
Not designated as hedging instruments
Interest rate contracts
	Other current assets	$	10			$	10
	Other deferred debits and other assets	5				5
	Derivative financial instruments			$	33			$	33
	Other deferred credits and other liabilities			22				22
Commodity contracts
	Other current assets	1
Energy management contracts
	Other current assets	11		2
	Other deferred debits and other assets	3
	Derivative financial instruments			9
	Other deferred credits and other liabilities			3
Total		$	30	$	69	$	15	$	55

 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 September 30,
Interest rate contracts	$	(1	)	$	(3	)	Interest expense	$	(1	)	$	(1	)
Nine Months Ended September 30,
Interest rate contracts	$	(6	)	$	(3	)	Interest expense	$	(2	)	$	(2	)

The Company:
	Gain (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 September 30,
Interest rate contracts	$	1		$	(3	)	Interest expense	$	(2	)	$	(2	)
Commodity contracts	(2		)	(4		)	Gas purchased for resale	—			(1		)
Total	$	(1	)	$	(7	)		$	(2	)	$	(3	)
Nine Months Ended September 30,
Interest rate contracts	$	(4	)	$	(3	)	Interest expense	$	(6	)	$	(6	)
Commodity contracts	—			(5		)	Gas purchased for resale	(6		)	(10		)
Total	$	(4	)	$	(8	)		$	(12	)	$	(16	)

As of September 30, 2016, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $1.7 million as a decrease to gas cost, assuming natural gas markets remain at their current levels, and approximately $6.6 million as an increase to interest expense.  As of September 30, 2016, all of the Company’s commodity cash flow hedges settle by their terms before the end of the third quarter of 2019.

As of September 30, 2016, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $1.9 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 (Loss) Reclassified from Deferred Accounts into Income
Millions of dollars	2016			2015			Location	2016			2015
Three Months Ended September 30,
Interest rate contracts	$	(24	)	$	(116	)	Other income	$	(1	)	—
Nine Months Ended September 30,
Interest rate contracts	$	(268	)	$	(79	)	Other income	$	(1	)	$	5

As of September 30, 2016, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from derivatives not designated as hedges will include $2.3 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	September 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
in Net Liability Position
Aggregate fair value of derivatives in net liability position	$	263.3	$	95.2	$	234.2	$	57.0
Fair value of collateral already posted	171.5		50.4		140.4		13.4
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	91.8		44.8		93.8		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 $6.0 million in commodity derivatives that are in a net asset position at September 30, 2016, compared to letters of credit in the amount 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 and derivative liabilities 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 September 30, 2016
Gross Amounts of Recognized Assets				$	6		$	6		$	12
Gross Amounts Offset in Statement of Financial Position				(1		)	(1		)	(2		)
Net Amounts Presented in Statement of Financial Position	—			5			5			10			—
Gross Amounts Not Offset - Financial Instruments										—
Gross Amounts Not Offset - Cash Collateral Received										—
Net Amount	—			$	5		$	5		$	10		—
Balance sheet location
Other current assets										$	8
Other deferred debits and other assets										2
Total										$	10		—
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

Derivative Liabilities	The Company												Consolidated SCE&G
Millions of dollars	Interest Rate Contracts			Commodity Contracts			Energy Management Contracts			Total			Interest Rate Contracts
As of September 30, 2016
Gross Amounts of Recognized Liabilities	$	261		$	1		$	6		$	268		$	234
Gross Amounts Offset in Statement of Financial Position				(1		)	(1		)	(2		)
Net Amounts Presented in Statement of Financial Position	261			—			5			266			234
Gross Amounts Not Offset - Financial Instruments										—
Gross Amounts Not Offset - Cash Collateral Posted	(169		)				(2		)	(171		)	(140		)
Net Amount	$	92		$	—		$	3		$	95		$	94
Balance sheet location
Derivative financial instruments										$	53		$	48
Other deferred credits and other liabilities										213			186
Total										$	266		$	234
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

9 Months Ended

Sep. 30, 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 September 30, 2016						As of December 31, 2015
	The Company				Consolidated SCE&G		The Company				Consolidated SCE&G
Millions of dollars	Level 1		Level 2		Level 2		Level 1		Level 2		Level 2
Assets:
Available for sale securities	$	14	—		—		$	11	—		—
Held to maturity securities	—		$	7	—		—		—		—
Interest rate contracts	—		—		—		—		$	15	$	15
Commodity contracts	6		—		—		1		—		—
Energy management contracts	1		5		—		—		14		—
Liabilities:
Interest rate contracts	—		261		$	234	—		87		65
Commodity contracts	1		—		—		1		4		—
Energy management contracts	—		9		—		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	September 30, 2016				December 31, 2015
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
The Company	$	6,588.6	$	7,674.0	$	5,997.6	$	6,445.7
Consolidated SCE&G	$	5,264.9	$	6,189.1	$	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 September 30, 2016						As of December 31, 2015
	The Company				Consolidated SCE&G		The Company				Consolidated SCE&G
Millions of dollars	Level 1		Level 2		Level 2		Level 1		Level 2		Level 2
Assets:
Available for sale securities	$	14	—		—		$	11	—		—
Held to maturity securities	—		$	7	—		—		—		—
Interest rate contracts	—		—		—		—		$	15	$	15
Commodity contracts	6		—		—		1		—		—
Energy management contracts	1		5		—		—		14		—
Liabilities:
Interest rate contracts	—		261		$	234	—		87		65
Commodity contracts	1		—		—		1		4		—
Energy management contracts	—		9		—		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	September 30, 2016				December 31, 2015
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
The Company	$	6,588.6	$	7,674.0	$	5,997.6	$	6,445.7
Consolidated SCE&G	$	5,264.9	$	6,189.1	$	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

9 Months Ended

Sep. 30, 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 September 30,
Service cost	$	4.4		$	6.6		$	0.8	$	1.2
Interest cost	9.8			9.6			3.0		2.8
Expected return on assets	(13.8		)	(15.5		)	—		—
Prior service cost amortization	1.0			1.0			0.1		0.1
Amortization of actuarial losses	3.7			3.2			0.2		0.4
Net periodic benefit cost	$	5.1		$	4.9		$	4.1	$	4.5

Nine months ended September 30,
Service cost	$	15.5		$	18.1		$	3.3	$	4.0
Interest cost	29.5			28.7			9.1		8.6
Expected return on assets	(41.9		)	(46.5		)	—		—
Prior service cost amortization	3.0			3.0			0.2		0.3
Amortization of actuarial losses	11.1			10.2			0.4		1.5
Net periodic benefit cost	$	17.2		$	13.5		$	13.0	$	14.4

Consolidated SCE&G	Pension Benefits						Other Postretirement Benefits
	2016			2015			2016		2015
Three months ended September 30,
Service cost	$	3.6		$	5.3		$	0.7	$	1.0
Interest cost	8.3			8.1			2.5		2.2
Expected return on assets	(11.7		)	(13.0		)	—		—
Prior service cost amortization	0.8			0.8			0.1		0.1
Amortization of actuarial losses	3.2			2.7			0.1		0.3
Net periodic benefit cost	$	4.2		$	3.9		$	3.4	$	3.6

Nine months ended September 30,
Service cost	$	12.7		$	14.5		$	2.7	$	3.2
Interest cost	25.0			24.1			7.5		6.8
Expected return on assets	(35.5		)	(39.1		)	—		—
Prior service cost amortization	2.5			2.5			0.2		0.2
Amortization of actuarial losses	9.4			8.6			0.3		1.2
Net periodic benefit cost	$	14.1		$	10.6		$	10.7	$	11.4

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 September 30,
Service cost	$	4.4		$	6.6		$	0.8	$	1.2
Interest cost	9.8			9.6			3.0		2.8
Expected return on assets	(13.8		)	(15.5		)	—		—
Prior service cost amortization	1.0			1.0			0.1		0.1
Amortization of actuarial losses	3.7			3.2			0.2		0.4
Net periodic benefit cost	$	5.1		$	4.9		$	4.1	$	4.5

Nine months ended September 30,
Service cost	$	15.5		$	18.1		$	3.3	$	4.0
Interest cost	29.5			28.7			9.1		8.6
Expected return on assets	(41.9		)	(46.5		)	—		—
Prior service cost amortization	3.0			3.0			0.2		0.3
Amortization of actuarial losses	11.1			10.2			0.4		1.5
Net periodic benefit cost	$	17.2		$	13.5		$	13.0	$	14.4

Consolidated SCE&G	Pension Benefits						Other Postretirement Benefits
	2016			2015			2016		2015
Three months ended September 30,
Service cost	$	3.6		$	5.3		$	0.7	$	1.0
Interest cost	8.3			8.1			2.5		2.2
Expected return on assets	(11.7		)	(13.0		)	—		—
Prior service cost amortization	0.8			0.8			0.1		0.1
Amortization of actuarial losses	3.2			2.7			0.1		0.3
Net periodic benefit cost	$	4.2		$	3.9		$	3.4	$	3.6

Nine months ended September 30,
Service cost	$	12.7		$	14.5		$	2.7	$	3.2
Interest cost	25.0			24.1			7.5		6.8
Expected return on assets	(35.5		)	(39.1		)	—		—
Prior service cost amortization	2.5			2.5			0.2		0.2
Amortization of actuarial losses	9.4			8.6			0.3		1.2
Net periodic benefit cost	$	14.1		$	10.6		$	10.7	$	11.4

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

9 Months Ended

Sep. 30, 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 $2.33 billion resulting from an event of a non-nuclear origin. In addition, a builder's risk insurance policy has been purchased from NEIL for the construction of the New Units. This policy provides the owners of the New Units up to $500 million of total coverage for accidental property damage occurring during construction. The NEIL policies, in the aggregate, are subject to a maximum loss of $2.75 billion for any single loss occurrence. All of the NEIL policies permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $45.8 million. SCE&G currently maintains an excess property insurance policy (for itself and on behalf of Santee Cooper) with EMANI. The policy provides coverage to 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 September 30, 2016, SCE&G’s investment in the New Units, including related transmission, totaled $4.2 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 Unit 2 and Unit 3 runs through the reinforced concrete activities necessary to support placement of shield building panels and the completion of shield building construction. 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 the critical path 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 initially 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. However, the Consortium continued to refine and update the Revised, Fully-Integrated Construction Schedule as certain designs were finalized, as construction progressed, and as additional information was received. See discussion of October 2015 Amendment below.

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 estimated gross construction cost (including escalation and AFC) were estimated to be $5.2 billion and $6.8 billion, respectively. These projections included 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 was to 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. However, see discussion of May 2016 Petition and September 2016 Settlement Agreement below.

October 2015 Amendment

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 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) provided 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) provided 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,

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

(vii) provided for an explicit definition of Change in Law designed to reduce the likelihood of certain future commercial disputes, with the Consortium also acknowledging and agreeing that the project scope includes providing New Units that meet the standards of the NRC approved Design Control Document Revision 19,

(viii) established a DRB process for certain commercial claims and disputes, and

(ix) eliminated the requirement or ability of any party to bring suit regarding disputes before substantial completion of the project.

The DRB is comprised of three members chosen by the parties to resolve construction-related claims.  Amounts in dispute of less than $5 million will be resolved by the DRB without recourse, and amounts in dispute greater than $5 million will be resolved by the DRB for the remainder of the construction of the New Units, with a reserved right to further arbitrate or to litigate such issues at the conclusion of construction.

Under the October 2015 Amendment, SCE&G’s total estimated project costs increased 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 a result, SCE&G's estimated gross construction cost for the project (including the effects of these change orders, escalation and AFC but excluding the fixed price option described below) totaled approximately $7.2 billion.

The October 2015 Amendment also provided 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 reduced by amounts paid since June 30, 2015. Under the fixed price option, the aggregate delay-related liquidated damages referred to in (iii) above would be capped at $338 million per New Unit (SCE&G’s 55% portion being approximately $186 million per New 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). See information below regarding the execution of this fixed price option, subject to SCPSC approval.

WEC has engaged Fluor to review and confirm the project schedule. The owners understand that this process has not been completed. The analysis by Fluor, to the extent that it is shared with the owners, could affect the owners’ expectations regarding the project schedule. In a discussion of the project status on September 26, 2016, and in response to SCE&G’s specific questioning regarding work crew efficiency and productivity and schedule mitigation efforts, WEC executive management stated that it had no reason to believe that the August 2019 and 2020 guaranteed completion dates would not be met. WEC submits monthly schedule updates, however, and it has reported that there are significant risks to achieving the current guaranteed substantial completion dates. WEC has also reported that it is continuing to develop detailed mitigation plans to address those risks.

May 2016 Petition and September 2016 Settlement Agreement

On May 26, 2016, SCE&G petitioned the SCPSC seeking approval to update the capital cost schedule and construction milestone schedule for the New Units consistent with the October 2015 Amendment. Within this petition, SCE&G also informed the SCPSC that it had notified WEC of its intent to elect the fixed price option, subject to concurrence by Santee Cooper and approval by the SCPSC. The petition reflected an increase in total project costs of approximately $852 million over the cost approved by the SCPSC in September 2015, of which approximately $505 million is directly attributable to the fixed price option. SCE&G's estimated gross construction cost for the project is now estimated to be approximately $7.7 billion, including owner’s costs, transmission, escalation and AFC. After receiving Santee Cooper's concurrence in June 2016, SCE&G executed the fixed price option on July 1, 2016, subject to SCPSC approval.

On July 1, 2016, SCE&G amended the May 26, 2016 petition by withdrawing its request to adjust its transmission capital costs forecast in the amount of $4.3 million and revising its proposed capital cost schedule accordingly (along with the associated escalation and AFC). This revision was made while SCE&G evaluates alternatives to installing additional capacitors in Summer Station's existing Unit 1 switchyard.

On September 1, 2016, SCE&G entered into a settlement agreement with ORS and certain other parties concerning SCE&G's May 26, 2016 petition. The settlement agreement supports approval of the fixed price option and the revised construction and capital cost schedules, including the guaranteed substantial completion dates of August 2019 and August 2020 for Units 2 and 3, respectively, and the inclusion of an additional $831 million in the capital cost schedule. The settling parties also agreed to revise the allowed return on equity for new nuclear construction from 10.5% to 10.25%. This revised return on equity would be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2017, until such time as the New Units are completed. In addition, SCE&G agreed that it will not file future requests to amend capital cost schedules prior to January 28, 2019. SCE&G also agreed that, in most circumstances, if the projected commercial operation date for Unit 2 is extended, the expiration of the January 28, 2019 moratorium will be extended by an equal amount of time. A public hearing on the petition, as amended, and the settlement agreement was held in October 2016, and the SCPSC is expected to issue its order in November 2016.

Construction Milestone Payment Schedule and Related DRB Activity

The October 2015 Amendment provided that the parties would agree upon a construction milestone payment schedule within five months of the effective date of the October 2015 Amendment or submit the issue to the DRB.  The parties agreed to two one-month extensions for discussion of the schedule through July 2016.  The parties were unable to reach an agreement on a schedule in that time period, and the owners referred the matter to the DRB on August 1, 2016. The dispute relates only to the timing of payments, with WEC asking for payments pursuant to a schedule which is more front loaded than the owners believe is appropriate. The total amount to be paid is not in dispute.

A hearing was held by the DRB on August 30 and 31, 2016, prior to which the parties filed statements of position and information to substantiate their respective positions. In connection with the DRB proceeding, WEC expressed concerns with the adoption of owners' proposed construction milestone payment schedule and indicated that the cash flow provided by that payment schedule may adversely affect WEC's ability to complete the project successfully.

On September 30, 2016, the parties received an order issued by the DRB instructing them to continue to work to develop a construction milestone payment schedule by November 3, 2016. The parties were unsuccessful in reaching an agreement by that date; therefore, the order provides that the DRB will conduct a further hearing on November 9, 2016, and will make a determination by November 30, 2016. During these efforts, payments will be made to WEC for October and November 2016 totaling $133 million (SCE&G's 55% portion being approximately $73.2 million) and $136.5 million (SCE&G's 55% portion being approximately $75.1 million), respectively. These payments are based on the DRB's findings concerning the approximate value of the work expected to be completed during these months and are in lieu of all other contractually-required payments related to (v) above during October and November 2016.

Based upon the information that has been presented by WEC in connection with the hearing and with respect to the matters at issue generally, SCE&G cannot predict whether a decision by the DRB which is more favorable to the owners will adversely affect WEC’s ability to complete the project or the construction schedule and costs.

As of September 30, 2016, payments related to (i) above had been made totaling $187.5 million (SCE&G's 55% portion being approximately $103.1 million). Also as of September 30, 2016, payments related to (v) above had been made totaling $930 million (SCE&G's 55% portion being $511.5 million), which included payments made during the initial five-month period described above, as required under the contract and payments agreed upon by the parties during the extensions described above and during the period the DRB was reviewing the matter.

Payment and Performance Obligations

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 standby letters of credit in lieu of payment and performance bonds from WEC 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.

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 project costs that arise through such dispute resolution processes (including those reflected in the October 2015 Amendment described above), as well as other project 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 is subject to customary closing conditions, including receipt of necessary regulatory approvals. This transaction will not affect the payment obligations between the parties during construction 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, SCE&G’s projected cost would be approximately $850 million for the additional 5% interest being acquired from Santee Cooper if the fixed price option is approved by the SCPSC.

Nuclear Production Tax Credits

The IRS has notified SCE&G that, subject to a national megawatt capacity limitation, the electricity to be produced by each of the New Units (advanced nuclear units, as defined) would qualify for nuclear production tax credits under Section 45J of the IRC to the extent that such New Unit is operational before January 1, 2021 and other eligibility requirements are met. These nuclear production tax credits (related to SCE&G's 55% share of both New Units) could total as much as approximately $1.4 billion. Such credits would be earned over the first eight years of each New Unit's operations and would be realized by SCE&G over those years or during allowable carry-forward periods. Based on 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 remains under review by the NRC and SCE&G does not anticipate any additional regulatory actions as a result of that review, but it cannot predict future regulatory activities or how such initiatives would impact construction or operation of the New Units.

Environmental

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 each state from one to three years to issue SIPs, which will ultimately define the specific compliance methodology that will be applied to existing units in that state. On February 9, 2016, the Supreme Court stayed the rule pending disposition of a petition of review of the rule in the Court of Appeals. The order of the Supreme Court has no immediate impact on SCE&G and GENCO or their generation operations. The Company and Consolidated SCE&G 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. The State of South Carolina has chosen to remain in the CSAPR program, even though recent court rulings exempted the state. This allows the state to remain compliant with regional haze standards. Air quality control installations that SCE&G and GENCO have already completed have positioned them to comply with the existing allowances set by the CSAPR. Any costs incurred to comply with CSAPR are expected to be recoverable through rates.

In April 2012, the EPA's MATS rule containing new standards for mercury and other specified air pollutants became effective. 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. In addition, SCE&G retired certain other coal-fired units during this time frame. The MATS rule has been the subject of ongoing litigation even while it remains in effect. Rulings on this litigation are not expected to have an impact on SCE&G or GENCO due to these retirements, conversions, and enhancements. 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. Any costs incurred to comply with the ELG Rule are expected to be recoverable through rates.

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

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

The Nuclear Waste Act required that the United States government accept and permanently dispose of high-level radioactive waste and spent nuclear fuel by January 31, 1998, and it imposed on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. SCE&G entered into a Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with the DOE in 1983. As of September 30, 2016, 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 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 $10.3 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 September 30, 2016, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $26.0 million and are included in regulatory assets.

Other

On October 8, 2016, Hurricane Matthew made landfall on the South Carolina coast affecting SCE&G’s service territory.  At its peak, more than 290,000 SCE&G electric customers were without service.  Incremental operation and maintenance costs to restore electric service will be applied to SCE&G’s SCPSC-approved storm damage reserve.  It is expected that such restoration costs will exceed the available balance of $2.0 million in SCE&G’s storm damage reserve, and SCE&G expects such additional costs to be deferred and recoverable through customers rates in future years.

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 $2.33 billion resulting from an event of a non-nuclear origin. In addition, a builder's risk insurance policy has been purchased from NEIL for the construction of the New Units. This policy provides the owners of the New Units up to $500 million of total coverage for accidental property damage occurring during construction. The NEIL policies, in the aggregate, are subject to a maximum loss of $2.75 billion for any single loss occurrence. All of the NEIL policies permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $45.8 million. SCE&G currently maintains an excess property insurance policy (for itself and on behalf of Santee Cooper) with EMANI. The policy provides coverage to 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 September 30, 2016, SCE&G’s investment in the New Units, including related transmission, totaled $4.2 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 Unit 2 and Unit 3 runs through the reinforced concrete activities necessary to support placement of shield building panels and the completion of shield building construction. 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 the critical path 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 initially 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. However, the Consortium continued to refine and update the Revised, Fully-Integrated Construction Schedule as certain designs were finalized, as construction progressed, and as additional information was received. See discussion of October 2015 Amendment below.

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 estimated gross construction cost (including escalation and AFC) were estimated to be $5.2 billion and $6.8 billion, respectively. These projections included 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 was to 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. However, see discussion of May 2016 Petition and September 2016 Settlement Agreement below.

October 2015 Amendment

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 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) provided 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) provided 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,

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

(vii) provided for an explicit definition of Change in Law designed to reduce the likelihood of certain future commercial disputes, with the Consortium also acknowledging and agreeing that the project scope includes providing New Units that meet the standards of the NRC approved Design Control Document Revision 19,

(viii) established a DRB process for certain commercial claims and disputes, and

(ix) eliminated the requirement or ability of any party to bring suit regarding disputes before substantial completion of the project.

The DRB is comprised of three members chosen by the parties to resolve construction-related claims.  Amounts in dispute of less than $5 million will be resolved by the DRB without recourse, and amounts in dispute greater than $5 million will be resolved by the DRB for the remainder of the construction of the New Units, with a reserved right to further arbitrate or to litigate such issues at the conclusion of construction.

Under the October 2015 Amendment, SCE&G’s total estimated project costs increased 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 a result, SCE&G's estimated gross construction cost for the project (including the effects of these change orders, escalation and AFC but excluding the fixed price option described below) totaled approximately $7.2 billion.

The October 2015 Amendment also provided 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 reduced by amounts paid since June 30, 2015. Under the fixed price option, the aggregate delay-related liquidated damages referred to in (iii) above would be capped at $338 million per New Unit (SCE&G’s 55% portion being approximately $186 million per New 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). See information below regarding the execution of this fixed price option, subject to SCPSC approval.

WEC has engaged Fluor to review and confirm the project schedule. The owners understand that this process has not been completed. The analysis by Fluor, to the extent that it is shared with the owners, could affect the owners’ expectations regarding the project schedule. In a discussion of the project status on September 26, 2016, and in response to SCE&G’s specific questioning regarding work crew efficiency and productivity and schedule mitigation efforts, WEC executive management stated that it had no reason to believe that the August 2019 and 2020 guaranteed completion dates would not be met. WEC submits monthly schedule updates, however, and it has reported that there are significant risks to achieving the current guaranteed substantial completion dates. WEC has also reported that it is continuing to develop detailed mitigation plans to address those risks.

May 2016 Petition and September 2016 Settlement Agreement

On May 26, 2016, SCE&G petitioned the SCPSC seeking approval to update the capital cost schedule and construction milestone schedule for the New Units consistent with the October 2015 Amendment. Within this petition, SCE&G also informed the SCPSC that it had notified WEC of its intent to elect the fixed price option, subject to concurrence by Santee Cooper and approval by the SCPSC. The petition reflected an increase in total project costs of approximately $852 million over the cost approved by the SCPSC in September 2015, of which approximately $505 million is directly attributable to the fixed price option. SCE&G's estimated gross construction cost for the project is now estimated to be approximately $7.7 billion, including owner’s costs, transmission, escalation and AFC. After receiving Santee Cooper's concurrence in June 2016, SCE&G executed the fixed price option on July 1, 2016, subject to SCPSC approval.

On July 1, 2016, SCE&G amended the May 26, 2016 petition by withdrawing its request to adjust its transmission capital costs forecast in the amount of $4.3 million and revising its proposed capital cost schedule accordingly (along with the associated escalation and AFC). This revision was made while SCE&G evaluates alternatives to installing additional capacitors in Summer Station's existing Unit 1 switchyard.

On September 1, 2016, SCE&G entered into a settlement agreement with ORS and certain other parties concerning SCE&G's May 26, 2016 petition. The settlement agreement supports approval of the fixed price option and the revised construction and capital cost schedules, including the guaranteed substantial completion dates of August 2019 and August 2020 for Units 2 and 3, respectively, and the inclusion of an additional $831 million in the capital cost schedule. The settling parties also agreed to revise the allowed return on equity for new nuclear construction from 10.5% to 10.25%. This revised return on equity would be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2017, until such time as the New Units are completed. In addition, SCE&G agreed that it will not file future requests to amend capital cost schedules prior to January 28, 2019. SCE&G also agreed that, in most circumstances, if the projected commercial operation date for Unit 2 is extended, the expiration of the January 28, 2019 moratorium will be extended by an equal amount of time. A public hearing on the petition, as amended, and the settlement agreement was held in October 2016, and the SCPSC is expected to issue its order in November 2016.

Construction Milestone Payment Schedule and Related DRB Activity

The October 2015 Amendment provided that the parties would agree upon a construction milestone payment schedule within five months of the effective date of the October 2015 Amendment or submit the issue to the DRB.  The parties agreed to two one-month extensions for discussion of the schedule through July 2016.  The parties were unable to reach an agreement on a schedule in that time period, and the owners referred the matter to the DRB on August 1, 2016. The dispute relates only to the timing of payments, with WEC asking for payments pursuant to a schedule which is more front loaded than the owners believe is appropriate. The total amount to be paid is not in dispute.

A hearing was held by the DRB on August 30 and 31, 2016, prior to which the parties filed statements of position and information to substantiate their respective positions. In connection with the DRB proceeding, WEC expressed concerns with the adoption of owners' proposed construction milestone payment schedule and indicated that the cash flow provided by that payment schedule may adversely affect WEC's ability to complete the project successfully.

On September 30, 2016, the parties received an order issued by the DRB instructing them to continue to work to develop a construction milestone payment schedule by November 3, 2016. The parties were unsuccessful in reaching an agreement by that date; therefore, the order provides that the DRB will conduct a further hearing on November 9, 2016, and will make a determination by November 30, 2016. During these efforts, payments will be made to WEC for October and November 2016 totaling $133 million (SCE&G's 55% portion being approximately $73.2 million) and $136.5 million (SCE&G's 55% portion being approximately $75.1 million), respectively. These payments are based on the DRB's findings concerning the approximate value of the work expected to be completed during these months and are in lieu of all other contractually-required payments related to (v) above during October and November 2016.

Based upon the information that has been presented by WEC in connection with the hearing and with respect to the matters at issue generally, SCE&G cannot predict whether a decision by the DRB which is more favorable to the owners will adversely affect WEC’s ability to complete the project or the construction schedule and costs.

As of September 30, 2016, payments related to (i) above had been made totaling $187.5 million (SCE&G's 55% portion being approximately $103.1 million). Also as of September 30, 2016, payments related to (v) above had been made totaling $930 million (SCE&G's 55% portion being $511.5 million), which included payments made during the initial five-month period described above, as required under the contract and payments agreed upon by the parties during the extensions described above and during the period the DRB was reviewing the matter.

Payment and Performance Obligations

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 standby letters of credit in lieu of payment and performance bonds from WEC 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.

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 project costs that arise through such dispute resolution processes (including those reflected in the October 2015 Amendment described above), as well as other project 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 is subject to customary closing conditions, including receipt of necessary regulatory approvals. This transaction will not affect the payment obligations between the parties during construction 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, SCE&G’s projected cost would be approximately $850 million for the additional 5% interest being acquired from Santee Cooper if the fixed price option is approved by the SCPSC.

Nuclear Production Tax Credits

The IRS has notified SCE&G that, subject to a national megawatt capacity limitation, the electricity to be produced by each of the New Units (advanced nuclear units, as defined) would qualify for nuclear production tax credits under Section 45J of the IRC to the extent that such New Unit is operational before January 1, 2021 and other eligibility requirements are met. These nuclear production tax credits (related to SCE&G's 55% share of both New Units) could total as much as approximately $1.4 billion. Such credits would be earned over the first eight years of each New Unit's operations and would be realized by SCE&G over those years or during allowable carry-forward periods. Based on 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 remains under review by the NRC and SCE&G does not anticipate any additional regulatory actions as a result of that review, but it cannot predict future regulatory activities or how such initiatives would impact construction or operation of the New Units.

Environmental

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 each state from one to three years to issue SIPs, which will ultimately define the specific compliance methodology that will be applied to existing units in that state. On February 9, 2016, the Supreme Court stayed the rule pending disposition of a petition of review of the rule in the Court of Appeals. The order of the Supreme Court has no immediate impact on SCE&G and GENCO or their generation operations. The Company and Consolidated SCE&G 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. The State of South Carolina has chosen to remain in the CSAPR program, even though recent court rulings exempted the state. This allows the state to remain compliant with regional haze standards. Air quality control installations that SCE&G and GENCO have already completed have positioned them to comply with the existing allowances set by the CSAPR. Any costs incurred to comply with CSAPR are expected to be recoverable through rates.

In April 2012, the EPA's MATS rule containing new standards for mercury and other specified air pollutants became effective. 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. In addition, SCE&G retired certain other coal-fired units during this time frame. The MATS rule has been the subject of ongoing litigation even while it remains in effect. Rulings on this litigation are not expected to have an impact on SCE&G or GENCO due to these retirements, conversions, and enhancements. 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. Any costs incurred to comply with the ELG Rule are expected to be recoverable through rates.

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

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

The Nuclear Waste Act required that the United States government accept and permanently dispose of high-level radioactive waste and spent nuclear fuel by January 31, 1998, and it imposed on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. SCE&G entered into a Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with the DOE in 1983. As of September 30, 2016, 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 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 $10.3 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 September 30, 2016, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $26.0 million and are included in regulatory assets.

Other

On October 8, 2016, Hurricane Matthew made landfall on the South Carolina coast affecting SCE&G’s service territory.  At its peak, more than 290,000 SCE&G electric customers were without service.  Incremental operation and maintenance costs to restore electric service will be applied to SCE&G’s SCPSC-approved storm damage reserve.  It is expected that such restoration costs will exceed the available balance of $2.0 million in SCE&G’s storm damage reserve, and SCE&G expects such additional costs to be deferred and recoverable through customers rates in future years. 

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SEGMENT OF BUSINESS INFORMATION

9 Months Ended

Sep. 30, 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 nine months ended September 30, 2015, operating income and net income for All Other include $235 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 September 30, 2016
Electric Operations	$	817	$	1		$	364		n/a
Gas Distribution	111		—			(14		)	n/a
Retail Gas Marketing	68		—			n/a			$	(3	)
Energy Marketing	97		35			n/a			2
All Other	—		100			—			(7		)
Adjustments/Eliminations	—		(136		)	(2		)	197
Consolidated Total	$	1,093	$	—		$	348		$	189

Nine Months Ended September 30, 2016
Electric Operations	$	2,035	$	4		$	784	n/a
Gas Distribution	538		1			79		n/a
Retail Gas Marketing	315		—			n/a		$	17
Energy Marketing	283		83			n/a		6
All Other	—		302			—		(14		)
Adjustments/Eliminations	—		(390		)	37		462
Consolidated Total	$	3,171	$	—		$	900	$	471

Three Months Ended September 30, 2015
Electric Operations	$	742	$	1		$	313		n/a
Gas Distribution	112		2			(13		)	n/a
Retail Gas Marketing	68		—			n/a			$	(3	)
Energy Marketing	146		34			n/a			(1		)
All Other	—		102			—			(9		)
Adjustments/Eliminations	—		(139		)	(8		)	162
Consolidated Total	$	1,068	$	—		$	292		$	149

Nine Months Ended September 30, 2015
Electric Operations	$	2,008		$	4		$	728	n/a
Gas Distribution	609			2			88		n/a
Retail Gas Marketing	344			—			n/a		$	18
Energy Marketing	461			101			n/a		8
All Other	5			309			237		188
Adjustments/Eliminations	(4		)	(416		)	42		434
Consolidated Total	$	3,423		$	—		$	1,095	$	648

Consolidated SCE&G
Millions of dollars	External Revenue		Operating Income			Earnings Available to Common Shareholder
Three Months Ended September 30, 2016
Electric Operations	$	818	$	364		n/a
Gas Distribution	64		(5		)	n/a
Adjustments/Eliminations	—		—			$	201
Consolidated Total	$	882	$	359		$	201

Nine Months Ended September 30, 2016
Electric Operations	$	2,039	$	784	n/a
Gas Distribution	253		32		n/a
Adjustments/Eliminations	—		—		$	423
Consolidated Total	$	2,292	$	816	$	423

Three Months Ended September 30, 2015
Electric Operations	$	743	$	313		n/a
Gas Distribution	63		(6		)	n/a
Adjustments/Eliminations	—		—			$	164
Consolidated Total	$	806	$	307		$	164

Nine Months Ended September 30, 2015
Electric Operations	$	2,013	$	728	n/a
Gas Distribution	275		35		n/a
Adjustments/Eliminations	—		—		$	394
Consolidated Total	$	2,288	$	763	$	394

Segment Assets	The Company				Consolidated SCE&G
	September 30,		December 31,		September 30,		December 31,
Millions of dollars	2016		2015		2016		2015
Electric Operations	$	11,543	$	10,883	$	11,543	$	10,883
Gas Distribution	2,757		2,606		801		757
Retail Gas Marketing	140		106		n/a		n/a
Energy Marketing	58		95		n/a		n/a
All Other	985		998		n/a		n/a
Adjustments/Eliminations	2,963		2,458		3,634		3,125
Consolidated Total	$	18,446	$	17,146	$	15,978	$	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 nine months ended September 30, 2015, operating income and net income for All Other include $235 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 September 30, 2016
Electric Operations	$	817	$	1		$	364		n/a
Gas Distribution	111		—			(14		)	n/a
Retail Gas Marketing	68		—			n/a			$	(3	)
Energy Marketing	97		35			n/a			2
All Other	—		100			—			(7		)
Adjustments/Eliminations	—		(136		)	(2		)	197
Consolidated Total	$	1,093	$	—		$	348		$	189

Nine Months Ended September 30, 2016
Electric Operations	$	2,035	$	4		$	784	n/a
Gas Distribution	538		1			79		n/a
Retail Gas Marketing	315		—			n/a		$	17
Energy Marketing	283		83			n/a		6
All Other	—		302			—		(14		)
Adjustments/Eliminations	—		(390		)	37		462
Consolidated Total	$	3,171	$	—		$	900	$	471

Three Months Ended September 30, 2015
Electric Operations	$	742	$	1		$	313		n/a
Gas Distribution	112		2			(13		)	n/a
Retail Gas Marketing	68		—			n/a			$	(3	)
Energy Marketing	146		34			n/a			(1		)
All Other	—		102			—			(9		)
Adjustments/Eliminations	—		(139		)	(8		)	162
Consolidated Total	$	1,068	$	—		$	292		$	149

Nine Months Ended September 30, 2015
Electric Operations	$	2,008		$	4		$	728	n/a
Gas Distribution	609			2			88		n/a
Retail Gas Marketing	344			—			n/a		$	18
Energy Marketing	461			101			n/a		8
All Other	5			309			237		188
Adjustments/Eliminations	(4		)	(416		)	42		434
Consolidated Total	$	3,423		$	—		$	1,095	$	648

Consolidated SCE&G
Millions of dollars	External Revenue		Operating Income			Earnings Available to Common Shareholder
Three Months Ended September 30, 2016
Electric Operations	$	818	$	364		n/a
Gas Distribution	64		(5		)	n/a
Adjustments/Eliminations	—		—			$	201
Consolidated Total	$	882	$	359		$	201

Nine Months Ended September 30, 2016
Electric Operations	$	2,039	$	784	n/a
Gas Distribution	253		32		n/a
Adjustments/Eliminations	—		—		$	423
Consolidated Total	$	2,292	$	816	$	423

Three Months Ended September 30, 2015
Electric Operations	$	743	$	313		n/a
Gas Distribution	63		(6		)	n/a
Adjustments/Eliminations	—		—			$	164
Consolidated Total	$	806	$	307		$	164

Nine Months Ended September 30, 2015
Electric Operations	$	2,013	$	728	n/a
Gas Distribution	275		35		n/a
Adjustments/Eliminations	—		—		$	394
Consolidated Total	$	2,288	$	763	$	394

Segment Assets	The Company				Consolidated SCE&G
	September 30,		December 31,		September 30,		December 31,
Millions of dollars	2016		2015		2016		2015
Electric Operations	$	11,543	$	10,883	$	11,543	$	10,883
Gas Distribution	2,757		2,606		801		757
Retail Gas Marketing	140		106		n/a		n/a
Energy Marketing	58		95		n/a		n/a
All Other	985		998		n/a		n/a
Adjustments/Eliminations	2,963		2,458		3,634		3,125
Consolidated Total	$	18,446	$	17,146	$	15,978	$	14,765

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AFFILIATED TRANSACTIONS

9 Months Ended

Sep. 30, 2016

Affiliated Transactions [Line Items]

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 $41.8 million and $66.3 million for the three months ended September 30, 2016 and 2015, respectively, and $138.6 million and $186.0 million for the nine months ended September 30, 2016 and 2015, respectively.  SCE&G’s total sales to this affiliate were $41.6 million and $65.9 million for the three months ended September 30, 2016 and 2015, respectively, and $137.8 million and $185.1 million for the nine months ended September 30, 2016 and 2015, respectively. SCE&G’s receivable from this affiliate was $4.0 million at September 30, 2016 and $12.8 million at December 31, 2015.  SCE&G’s payable to this affiliate was $4.1 million at September 30, 2016 and $12.9 million at December 31, 2015.

SCEG

Affiliated Transactions [Line Items]

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 $41.8 million and $66.3 million for the three months ended September 30, 2016 and 2015, respectively, and $138.6 million and $186.0 million for the nine months ended September 30, 2016 and 2015, respectively.  SCE&G’s total sales to this affiliate were $41.6 million and $65.9 million for the three months ended September 30, 2016 and 2015, respectively, and $137.8 million and $185.1 million for the nine months ended September 30, 2016 and 2015, respectively. SCE&G’s receivable from this affiliate was $4.0 million at September 30, 2016 and $12.8 million at December 31, 2015.  SCE&G’s payable to this affiliate was $4.1 million at September 30, 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 $34.8 million and $34 million for the three months ended September 30, 2016 and 2015, respectively, and $83.1 million and $101.4 million for the nine months ended September 30, 2016 and 2015, respectively.  SCE&G’s payables to SEMI for such purchases were $10.9 million at September 30, 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, telecommunications, customer support, marketing and sales, human resources, corporate compliance, purchasing, financial, risk management, public affairs, legal, investor relations, gas supply and capacity management, strategic planning, general administrative, and retirement benefits. In addition, SCANA Services processes and pays invoices for Consolidated SCE&G and is reimbursed. Costs for these services were $80.4 million and $80.8 million for the three months ended September 30, 2016 and 2015, respectively, and $236.4 million and $226.0 million for the nine months ended September 30, 2016 and 2015, respectively. Consolidated SCE&G's payables to SCANA Services for these services were $50.8 million at September 30, 2016 and $57.0 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)

9 Months Ended

Sep. 30, 2016

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 $483 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 4.

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).

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, through an agency relationship, 41% and 46% of PSNC Energy’s natural gas inventory at September 30, 2016 and December 31, 2015, respectively, with a carrying value of $13.1 million and $17.7 million, respectively.  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 [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. When applicable, 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.

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.

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 earlier revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive

in exchange for those goods or services. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018. The guidance permits adoption using a retrospective method, with options to elect certain practical expedients, or recognition of a cumulative effect in the year of initial adoption. The Company and Consolidated SCE&G have not determined which method of adoption will be employed or what practical expedients may be elected. The Company and Consolidated SCE&G have not determined the impact this guidance will have on their respective financial statements. However, the identification of implementation project team members and the analysis of contracts with customers to which the guidance might be applicable, particularly large customer contracts, have begun.

In 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 and have determined that the adoption of this guidance will not have a significant impact on their respective financial statements.

In January 2016, the FASB issued accounting guidance that will change how entities measure certain equity investments and financial liabilities, among other things. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018. The Company and Consolidated SCE&G are evaluating this guidance and do not anticipate that its adoption will have a significant impact on their respective financial statements.

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

leases. The guidance applies a right-of-use model and, for lessees, requires all leases with a duration over 12 months to be

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

and without consideration of any regulatory accounting requirements which may apply, depending primarily on the nature of the assets and the relative consumption of them, lease costs will be recognized either through the separate amortization of the right-of-use asset and the recognition of the interest cost related to the payment obligation, or through the recording of a combined straight-line rental expense. For lessors, the guidance calls for the recognition of income either through the derecognition of assets and subsequent recording of interest income on lease amounts receivable, or through the recognition of rental income on a straight-line basis, also depending on the nature of the assets and relative consumption. The guidance will be effective for years beginning in 2019. The Company and Consolidated SCE&G have not determined what impact this guidance will have on their respective financial statements. However, the identification of implementation project team members and the initial identification and analysis of leasing and related contracts to which the guidance might be applicable have begun.

In 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, based on the nature of their current share-based awards practices, do not anticipate that its adoption will have a significant impact on their respective financial statements.

In June 2016, the FASB issued accounting guidance requiring the use of a current expected credit loss impairment model for certain financial instruments. The new model is applicable to trade receivables and most debt instruments, among other financial instruments, and is intended to result in impairment losses being recognized earlier than under current guidance. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted in 2019. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective financial statements.

In August 2016, the FASB issued accounting guidance to reduce diversity in cash flow classification related to certain transactions. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018 and do not anticipate that its adoption will impact their respective financial statements.

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 $483 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 4.

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 earlier revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive

in exchange for those goods or services. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018. The guidance permits adoption using a retrospective method, with options to elect certain practical expedients, or recognition of a cumulative effect in the year of initial adoption. The Company and Consolidated SCE&G have not determined which method of adoption will be employed or what practical expedients may be elected. The Company and Consolidated SCE&G have not determined the impact this guidance will have on their respective financial statements. However, the identification of implementation project team members and the analysis of contracts with customers to which the guidance might be applicable, particularly large customer contracts, have begun.

In 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 and have determined that the adoption of this guidance will not have a significant impact on their respective financial statements.

In January 2016, the FASB issued accounting guidance that will change how entities measure certain equity investments and financial liabilities, among other things. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018. The Company and Consolidated SCE&G are evaluating this guidance and do not anticipate that its adoption will have a significant impact on their respective financial statements.

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

leases. The guidance applies a right-of-use model and, for lessees, requires all leases with a duration over 12 months to be

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

and without consideration of any regulatory accounting requirements which may apply, depending primarily on the nature of the assets and the relative consumption of them, lease costs will be recognized either through the separate amortization of the right-of-use asset and the recognition of the interest cost related to the payment obligation, or through the recording of a combined straight-line rental expense. For lessors, the guidance calls for the recognition of income either through the derecognition of assets and subsequent recording of interest income on lease amounts receivable, or through the recognition of rental income on a straight-line basis, also depending on the nature of the assets and relative consumption. The guidance will be effective for years beginning in 2019. The Company and Consolidated SCE&G have not determined what impact this guidance will have on their respective financial statements. However, the identification of implementation project team members and the initial identification and analysis of leasing and related contracts to which the guidance might be applicable have begun.

In 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, based on the nature of their current share-based awards practices, do not anticipate that its adoption will have a significant impact on their respective financial statements.

In June 2016, the FASB issued accounting guidance requiring the use of a current expected credit loss impairment model for certain financial instruments. The new model is applicable to trade receivables and most debt instruments, among other financial instruments, and is intended to result in impairment losses being recognized earlier than under current guidance. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted in 2019. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective financial statements.

In August 2016, the FASB issued accounting guidance to reduce diversity in cash flow classification related to certain transactions. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018 and do not anticipate that its adoption will impact their respective financial statements.

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RATE AND OTHER REGULATORY MATTERS (Tables)

9 Months Ended

Sep. 30, 2016

Regulatory Assets

Schedule of Regulatory Assets [Table Text Block]

.

	The Company				Consolidated SCE&G
Millions of dollars	September 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
Regulatory Assets:
Accumulated deferred income taxes	$	301	$	298	$	294	$	291
Environmental remediation costs	33		42		26		35
AROs and related funding	402		405		380		384
Deferred employee benefit plan costs	311		325		282		295
Deferred losses on interest rate derivatives	791		535		791		535
Unrecovered plant	119		127		119		127
DSM Programs	58		61		58		61
Deferred costs related to uncertain tax position	14		—		14		—
Other	173		144		150		129
Total Regulatory Assets	$	2,202	$	1,937	$	2,114	$	1,857

Schedule of Regulatory Liabilities [Table Text Block]

Regulatory Liabilities:
Asset removal costs	$	756	$	732	$	533	$	519
Deferred gains on interest rate derivatives	80		96		80		96
Other	28		27		17		20
Total Regulatory Liabilities	$	864	$	855	$	630	$	635

SCEG

Regulatory Assets

Schedule of Regulatory Assets [Table Text Block]

	The Company				Consolidated SCE&G
Millions of dollars	September 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
Regulatory Assets:
Accumulated deferred income taxes	$	301	$	298	$	294	$	291
Environmental remediation costs	33		42		26		35
AROs and related funding	402		405		380		384
Deferred employee benefit plan costs	311		325		282		295
Deferred losses on interest rate derivatives	791		535		791		535
Unrecovered plant	119		127		119		127
DSM Programs	58		61		58		61
Deferred costs related to uncertain tax position	14		—		14		—
Other	173		144		150		129
Total Regulatory Assets	$	2,202	$	1,937	$	2,114	$	1,857

Schedule of Regulatory Liabilities [Table Text Block]

Regulatory Liabilities:
Asset removal costs	$	756	$	732	$	533	$	519
Deferred gains on interest rate derivatives	80		96		80		96
Other	28		27		17		20
Total Regulatory Liabilities	$	864	$	855	$	630	$	635

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LONG-TERM AND SHORT-TERM DEBT (Tables)

9 Months Ended

Sep. 30, 2016

Short-term Debt [Line Items]

Schedule of Line of Credit Facilities [Table Text Block]

	September 30, 2016
Millions of dollars	Total		SCANA			Consolidated SCE&G			PSNC  Energy
Lines of credit:
Five-year, expiring December 2020	$	1,300.0	$	400.0		$	700.0		$	200.0
Fuel Company five-year, expiring December 2020	$	500.0	—			$	500.0		—
Three-year, expiring December 2018	$	200.0	—			$	200.0		—
Total committed long-term	$	2,000.0	$	400.0		$	1,400.0		$	200.0
Outstanding commercial paper (270 or fewer days)	$	777.6	$	16.0		$	714.2		$	47.4
Weighted average interest rate			0.93		%	0.84		%	0.83		%
Letters of credit supported by LOC	$	3.3	$	3.0		$	0.3		—
Available	$	1,219.1	$	381.0		$	685.5		$	152.6

	December 31, 2015
Millions of dollars	Total		SCANA			Consolidated SCE&G			PSNC  Energy
Lines of credit:
Five-year, expiring December 2020	$	1,300.0	$	400.0		$	700.0		$	200.0
Fuel Company five-year, expiring December 2020	$	500.0	—			$	500.0		—
Three-year, expiring December 2018	$	200.0	—			$	200.0		—
Total committed long-term	$	2,000.0	$	400.0		$	1,400.0		$	200.0
Outstanding commercial paper (270 or fewer days)	$	531.4	$	37.4		$	420.2		$	73.8
Weighted average interest rate			1.19		%	0.74		%	0.77		%
Letters of credit supported by LOC	$	3.3	$	3.0		$	0.3		—
Available	$	1,465.4	$	359.6		$	979.6		$	126.2

SCEG

Short-term Debt [Line Items]

Schedule of Line of Credit Facilities [Table Text Block]

	September 30, 2016
Millions of dollars	Total		SCANA			Consolidated SCE&G			PSNC  Energy
Lines of credit:
Five-year, expiring December 2020	$	1,300.0	$	400.0		$	700.0		$	200.0
Fuel Company five-year, expiring December 2020	$	500.0	—			$	500.0		—
Three-year, expiring December 2018	$	200.0	—			$	200.0		—
Total committed long-term	$	2,000.0	$	400.0		$	1,400.0		$	200.0
Outstanding commercial paper (270 or fewer days)	$	777.6	$	16.0		$	714.2		$	47.4
Weighted average interest rate			0.93		%	0.84		%	0.83		%
Letters of credit supported by LOC	$	3.3	$	3.0		$	0.3		—
Available	$	1,219.1	$	381.0		$	685.5		$	152.6

	December 31, 2015
Millions of dollars	Total		SCANA			Consolidated SCE&G			PSNC  Energy
Lines of credit:
Five-year, expiring December 2020	$	1,300.0	$	400.0		$	700.0		$	200.0
Fuel Company five-year, expiring December 2020	$	500.0	—			$	500.0		—
Three-year, expiring December 2018	$	200.0	—			$	200.0		—
Total committed long-term	$	2,000.0	$	400.0		$	1,400.0		$	200.0
Outstanding commercial paper (270 or fewer days)	$	531.4	$	37.4		$	420.2		$	73.8
Weighted average interest rate			1.19		%	0.74		%	0.77		%
Letters of credit supported by LOC	$	3.3	$	3.0		$	0.3		—
Available	$	1,465.4	$	359.6		$	979.6		$	126.2

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DERIVATIVE FINANCIAL INSTRUMENTS (Tables)

9 Months Ended

Sep. 30, 2016

Derivative [Line Items]

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

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

	Commodity and Other Energy Management Contracts (in MMBTU)
		Retail Gas
Hedge designation	Gas Distribution	Marketing	Energy Marketing	Total
As of September 30, 2016
Commodity contracts	8,600,000	11,781,000	4,223,500	24,604,500
Energy management contracts (a)	—	—	35,795,914	35,795,914
Total (a)	8,600,000	11,781,000	40,019,414	60,400,414
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 1,028,115 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	September 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
Designated as hedging instruments	$	115.6	$	120.0	$	36.4	$	36.4
Not designated as hedging instruments	1,285.0		1,235.0		1,285.0		1,235.0

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

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

Fair Values of Derivative Instruments
		The Company				Consolidated SCE&G
Millions of dollars	Balance Sheet Location	Asset		Liability		Asset		Liability
As of September 30, 2016
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	3			$	1
	Other deferred credits and other liabilities			39				14
Commodity contracts
	Other current assets	$	3	1
Total		$	3	$	43	—		$	15
Not designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	47			$	47
	Other deferred credits and other liabilities			172				172
Commodity contracts
	Other current assets	$	3
Energy management contracts
	Other current assets	4
	Other deferred debits and other assets	2
	Derivative financial instruments			4
	Other deferred credits and other liabilities			2
Total		$	9	$	225	—		$	219
As of December 31, 2015
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	4			$	1
	Other deferred credits and other liabilities			28				9
Commodity contracts
	Other current assets			1
	Derivative financial instruments			4
Total		—		$	37	—		$	10
Not designated as hedging instruments
Interest rate contracts
	Other current assets	$	10			$	10
	Other deferred debits and other assets	5				5
	Derivative financial instruments			$	33			$	33
	Other deferred credits and other liabilities			22				22
Commodity contracts
	Other current assets	1
Energy management contracts
	Other current assets	11		2
	Other deferred debits and other assets	3
	Derivative financial instruments			9
	Other deferred credits and other liabilities			3
Total		$	30	$	69	$	15	$	55

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

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 September 30,
Interest rate contracts	$	(1	)	$	(3	)	Interest expense	$	(1	)	$	(1	)
Nine Months Ended September 30,
Interest rate contracts	$	(6	)	$	(3	)	Interest expense	$	(2	)	$	(2	)

The Company:
	Gain (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 September 30,
Interest rate contracts	$	1		$	(3	)	Interest expense	$	(2	)	$	(2	)
Commodity contracts	(2		)	(4		)	Gas purchased for resale	—			(1		)
Total	$	(1	)	$	(7	)		$	(2	)	$	(3	)
Nine Months Ended September 30,
Interest rate contracts	$	(4	)	$	(3	)	Interest expense	$	(6	)	$	(6	)
Commodity contracts	—			(5		)	Gas purchased for resale	(6		)	(10		)
Total	$	(4	)	$	(8	)		$	(12	)	$	(16	)

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

Derivatives not designated as Hedging Instruments
The Company and Consolidated SCE&G:
	Loss Deferred in Regulatory Accounts							Gain (Loss) Reclassified from Deferred Accounts into Income
Millions of dollars	2016			2015			Location	2016			2015
Three Months Ended September 30,
Interest rate contracts	$	(24	)	$	(116	)	Other income	$	(1	)	—
Nine Months Ended September 30,
Interest rate contracts	$	(268	)	$	(79	)	Other income	$	(1	)	$	5

Disclosure of Credit Derivatives [Table Text Block]

Derivative Contracts with Credit Contingent Features
	The Company				Consolidated SCE&G
Millions of dollars	September 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
in Net Liability Position
Aggregate fair value of derivatives in net liability position	$	263.3	$	95.2	$	234.2	$	57.0
Fair value of collateral already posted	171.5		50.4		140.4		13.4
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	91.8		44.8		93.8		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 and derivative liabilities 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 September 30, 2016
Gross Amounts of Recognized Assets				$	6		$	6		$	12
Gross Amounts Offset in Statement of Financial Position				(1		)	(1		)	(2		)
Net Amounts Presented in Statement of Financial Position	—			5			5			10			—
Gross Amounts Not Offset - Financial Instruments										—
Gross Amounts Not Offset - Cash Collateral Received										—
Net Amount	—			$	5		$	5		$	10		—
Balance sheet location
Other current assets										$	8
Other deferred debits and other assets										2
Total										$	10		—
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]

Derivative Liabilities	The Company												Consolidated SCE&G
Millions of dollars	Interest Rate Contracts			Commodity Contracts			Energy Management Contracts			Total			Interest Rate Contracts
As of September 30, 2016
Gross Amounts of Recognized Liabilities	$	261		$	1		$	6		$	268		$	234
Gross Amounts Offset in Statement of Financial Position				(1		)	(1		)	(2		)
Net Amounts Presented in Statement of Financial Position	261			—			5			266			234
Gross Amounts Not Offset - Financial Instruments										—
Gross Amounts Not Offset - Cash Collateral Posted	(169		)				(2		)	(171		)	(140		)
Net Amount	$	92		$	—		$	3		$	95		$	94
Balance sheet location
Derivative financial instruments										$	53		$	48
Other deferred credits and other liabilities										213			186
Total										$	266		$	234
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]

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	September 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
Designated as hedging instruments	$	115.6	$	120.0	$	36.4	$	36.4
Not designated as hedging instruments	1,285.0		1,235.0		1,285.0		1,235.0

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

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

Fair Values of Derivative Instruments
		The Company				Consolidated SCE&G
Millions of dollars	Balance Sheet Location	Asset		Liability		Asset		Liability
As of September 30, 2016
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	3			$	1
	Other deferred credits and other liabilities			39				14
Commodity contracts
	Other current assets	$	3	1
Total		$	3	$	43	—		$	15
Not designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	47			$	47
	Other deferred credits and other liabilities			172				172
Commodity contracts
	Other current assets	$	3
Energy management contracts
	Other current assets	4
	Other deferred debits and other assets	2
	Derivative financial instruments			4
	Other deferred credits and other liabilities			2
Total		$	9	$	225	—		$	219
As of December 31, 2015
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments			$	4			$	1
	Other deferred credits and other liabilities			28				9
Commodity contracts
	Other current assets			1
	Derivative financial instruments			4
Total		—		$	37	—		$	10
Not designated as hedging instruments
Interest rate contracts
	Other current assets	$	10			$	10
	Other deferred debits and other assets	5				5
	Derivative financial instruments			$	33			$	33
	Other deferred credits and other liabilities			22				22
Commodity contracts
	Other current assets	1
Energy management contracts
	Other current assets	11		2
	Other deferred debits and other assets	3
	Derivative financial instruments			9
	Other deferred credits and other liabilities			3
Total		$	30	$	69	$	15	$	55

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

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 September 30,
Interest rate contracts	$	(1	)	$	(3	)	Interest expense	$	(1	)	$	(1	)
Nine Months Ended September 30,
Interest rate contracts	$	(6	)	$	(3	)	Interest expense	$	(2	)	$	(2	)

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

Derivatives not designated as Hedging Instruments
The Company and Consolidated SCE&G:
	Loss Deferred in Regulatory Accounts							Gain (Loss) Reclassified from Deferred Accounts into Income
Millions of dollars	2016			2015			Location	2016			2015
Three Months Ended September 30,
Interest rate contracts	$	(24	)	$	(116	)	Other income	$	(1	)	—
Nine Months Ended September 30,
Interest rate contracts	$	(268	)	$	(79	)	Other income	$	(1	)	$	5

Disclosure of Credit Derivatives [Table Text Block]

Derivative Contracts with Credit Contingent Features
	The Company				Consolidated SCE&G
Millions of dollars	September 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
in Net Liability Position
Aggregate fair value of derivatives in net liability position	$	263.3	$	95.2	$	234.2	$	57.0
Fair value of collateral already posted	171.5		50.4		140.4		13.4
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	91.8		44.8		93.8		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 and derivative liabilities 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 September 30, 2016
Gross Amounts of Recognized Assets				$	6		$	6		$	12
Gross Amounts Offset in Statement of Financial Position				(1		)	(1		)	(2		)
Net Amounts Presented in Statement of Financial Position	—			5			5			10			—
Gross Amounts Not Offset - Financial Instruments										—
Gross Amounts Not Offset - Cash Collateral Received										—
Net Amount	—			$	5		$	5		$	10		—
Balance sheet location
Other current assets										$	8
Other deferred debits and other assets										2
Total										$	10		—
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]

Derivative Liabilities	The Company												Consolidated SCE&G
Millions of dollars	Interest Rate Contracts			Commodity Contracts			Energy Management Contracts			Total			Interest Rate Contracts
As of September 30, 2016
Gross Amounts of Recognized Liabilities	$	261		$	1		$	6		$	268		$	234
Gross Amounts Offset in Statement of Financial Position				(1		)	(1		)	(2		)
Net Amounts Presented in Statement of Financial Position	261			—			5			266			234
Gross Amounts Not Offset - Financial Instruments										—
Gross Amounts Not Offset - Cash Collateral Posted	(169		)				(2		)	(171		)	(140		)
Net Amount	$	92		$	—		$	3		$	95		$	94
Balance sheet location
Derivative financial instruments										$	53		$	48
Other deferred credits and other liabilities										213			186
Total										$	266		$	234
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

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FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Tables)

9 Months Ended

Sep. 30, 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 September 30, 2016						As of December 31, 2015
	The Company				Consolidated SCE&G		The Company				Consolidated SCE&G
Millions of dollars	Level 1		Level 2		Level 2		Level 1		Level 2		Level 2
Assets:
Available for sale securities	$	14	—		—		$	11	—		—
Held to maturity securities	—		$	7	—		—		—		—
Interest rate contracts	—		—		—		—		$	15	$	15
Commodity contracts	6		—		—		1		—		—
Energy management contracts	1		5		—		—		14		—
Liabilities:
Interest rate contracts	—		261		$	234	—		87		65
Commodity contracts	1		—		—		1		4		—
Energy management contracts	—		9		—		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	September 30, 2016				December 31, 2015
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
The Company	$	6,588.6	$	7,674.0	$	5,997.6	$	6,445.7
Consolidated SCE&G	$	5,264.9	$	6,189.1	$	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 September 30, 2016						As of December 31, 2015
	The Company				Consolidated SCE&G		The Company				Consolidated SCE&G
Millions of dollars	Level 1		Level 2		Level 2		Level 1		Level 2		Level 2
Assets:
Available for sale securities	$	14	—		—		$	11	—		—
Held to maturity securities	—		$	7	—		—		—		—
Interest rate contracts	—		—		—		—		$	15	$	15
Commodity contracts	6		—		—		1		—		—
Energy management contracts	1		5		—		—		14		—
Liabilities:
Interest rate contracts	—		261		$	234	—		87		65
Commodity contracts	1		—		—		1		4		—
Energy management contracts	—		9		—		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	September 30, 2016				December 31, 2015
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
The Company	$	6,588.6	$	7,674.0	$	5,997.6	$	6,445.7
Consolidated SCE&G	$	5,264.9	$	6,189.1	$	4,769.0	$	5,129.1

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EMPLOYEE BENEFIT PLANS (Tables)

9 Months Ended

Sep. 30, 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 September 30,
Service cost	$	4.4		$	6.6		$	0.8	$	1.2
Interest cost	9.8			9.6			3.0		2.8
Expected return on assets	(13.8		)	(15.5		)	—		—
Prior service cost amortization	1.0			1.0			0.1		0.1
Amortization of actuarial losses	3.7			3.2			0.2		0.4
Net periodic benefit cost	$	5.1		$	4.9		$	4.1	$	4.5

Nine months ended September 30,
Service cost	$	15.5		$	18.1		$	3.3	$	4.0
Interest cost	29.5			28.7			9.1		8.6
Expected return on assets	(41.9		)	(46.5		)	—		—
Prior service cost amortization	3.0			3.0			0.2		0.3
Amortization of actuarial losses	11.1			10.2			0.4		1.5
Net periodic benefit cost	$	17.2		$	13.5		$	13.0	$	14.4

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 September 30,
Service cost	$	3.6		$	5.3		$	0.7	$	1.0
Interest cost	8.3			8.1			2.5		2.2
Expected return on assets	(11.7		)	(13.0		)	—		—
Prior service cost amortization	0.8			0.8			0.1		0.1
Amortization of actuarial losses	3.2			2.7			0.1		0.3
Net periodic benefit cost	$	4.2		$	3.9		$	3.4	$	3.6

Nine months ended September 30,
Service cost	$	12.7		$	14.5		$	2.7	$	3.2
Interest cost	25.0			24.1			7.5		6.8
Expected return on assets	(35.5		)	(39.1		)	—		—
Prior service cost amortization	2.5			2.5			0.2		0.2
Amortization of actuarial losses	9.4			8.6			0.3		1.2
Net periodic benefit cost	$	14.1		$	10.6		$	10.7	$	11.4

XML

SEGMENT OF BUSINESS INFORMATION (Tables)

9 Months Ended

Sep. 30, 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 September 30, 2016
Electric Operations	$	817	$	1		$	364		n/a
Gas Distribution	111		—			(14		)	n/a
Retail Gas Marketing	68		—			n/a			$	(3	)
Energy Marketing	97		35			n/a			2
All Other	—		100			—			(7		)
Adjustments/Eliminations	—		(136		)	(2		)	197
Consolidated Total	$	1,093	$	—		$	348		$	189

Nine Months Ended September 30, 2016
Electric Operations	$	2,035	$	4		$	784	n/a
Gas Distribution	538		1			79		n/a
Retail Gas Marketing	315		—			n/a		$	17
Energy Marketing	283		83			n/a		6
All Other	—		302			—		(14		)
Adjustments/Eliminations	—		(390		)	37		462
Consolidated Total	$	3,171	$	—		$	900	$	471

Three Months Ended September 30, 2015
Electric Operations	$	742	$	1		$	313		n/a
Gas Distribution	112		2			(13		)	n/a
Retail Gas Marketing	68		—			n/a			$	(3	)
Energy Marketing	146		34			n/a			(1		)
All Other	—		102			—			(9		)
Adjustments/Eliminations	—		(139		)	(8		)	162
Consolidated Total	$	1,068	$	—		$	292		$	149

Nine Months Ended September 30, 2015
Electric Operations	$	2,008		$	4		$	728	n/a
Gas Distribution	609			2			88		n/a
Retail Gas Marketing	344			—			n/a		$	18
Energy Marketing	461			101			n/a		8
All Other	5			309			237		188
Adjustments/Eliminations	(4		)	(416		)	42		434
Consolidated Total	$	3,423		$	—		$	1,095	$	648

Consolidated SCE&G
Millions of dollars	External Revenue		Operating Income			Earnings Available to Common Shareholder
Three Months Ended September 30, 2016
Electric Operations	$	818	$	364		n/a
Gas Distribution	64		(5		)	n/a
Adjustments/Eliminations	—		—			$	201
Consolidated Total	$	882	$	359		$	201

Nine Months Ended September 30, 2016
Electric Operations	$	2,039	$	784	n/a
Gas Distribution	253		32		n/a
Adjustments/Eliminations	—		—		$	423
Consolidated Total	$	2,292	$	816	$	423

Three Months Ended September 30, 2015
Electric Operations	$	743	$	313		n/a
Gas Distribution	63		(6		)	n/a
Adjustments/Eliminations	—		—			$	164
Consolidated Total	$	806	$	307		$	164

Nine Months Ended September 30, 2015
Electric Operations	$	2,013	$	728	n/a
Gas Distribution	275		35		n/a
Adjustments/Eliminations	—		—		$	394
Consolidated Total	$	2,288	$	763	$	394

Segment Assets	The Company				Consolidated SCE&G
	September 30,		December 31,		September 30,		December 31,
Millions of dollars	2016		2015		2016		2015
Electric Operations	$	11,543	$	10,883	$	11,543	$	10,883
Gas Distribution	2,757		2,606		801		757
Retail Gas Marketing	140		106		n/a		n/a
Energy Marketing	58		95		n/a		n/a
All Other	985		998		n/a		n/a
Adjustments/Eliminations	2,963		2,458		3,634		3,125
Consolidated Total	$	18,446	$	17,146	$	15,978	$	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 September 30, 2016
Electric Operations	$	818	$	364		n/a
Gas Distribution	64		(5		)	n/a
Adjustments/Eliminations	—		—			$	201
Consolidated Total	$	882	$	359		$	201

Nine Months Ended September 30, 2016
Electric Operations	$	2,039	$	784	n/a
Gas Distribution	253		32		n/a
Adjustments/Eliminations	—		—		$	423
Consolidated Total	$	2,292	$	816	$	423

Three Months Ended September 30, 2015
Electric Operations	$	743	$	313		n/a
Gas Distribution	63		(6		)	n/a
Adjustments/Eliminations	—		—			$	164
Consolidated Total	$	806	$	307		$	164

Nine Months Ended September 30, 2015
Electric Operations	$	2,013	$	728	n/a
Gas Distribution	275		35		n/a
Adjustments/Eliminations	—		—		$	394
Consolidated Total	$	2,288	$	763	$	394

Segment Assets	The Company				Consolidated SCE&G
	September 30,		December 31,		September 30,		December 31,
Millions of dollars	2016		2015		2016		2015
Electric Operations	$	11,543	$	10,883	$	11,543	$	10,883
Gas Distribution	2,757		2,606		801		757
Retail Gas Marketing	140		106		n/a		n/a
Energy Marketing	58		95		n/a		n/a
All Other	985		998		n/a		n/a
Adjustments/Eliminations	2,963		2,458		3,634		3,125
Consolidated Total	$	18,446	$	17,146	$	15,978	$	14,765

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2016 USD ($) MW	Dec. 31, 2015 USD ($)
Significant Accounting Policies
Pre-tax gain on sale of CGT and SCI		$ 342.0
Property, Plant and Equipment, Net	$ 277.0	280.0
Reclassifications, Cash Flow Statement, Regulatory Assets, Use Of Cash	66.0
Reclassifications, Cash Flow Statement, Regulatory liabilities, Source of Cash	(5.0)
Reclassifications, Cash Flow Statement, Other assets, use of cash	(6.0)
Reclassifications, Cash Flow Statement, Derivative Financial Instruments, Source Of Cash	(100.0)
Reclassifications, Cash Flow Statement, Other Liabilities, Source Of Cash	45.0
SCEG
Significant Accounting Policies
Property, Plant and Equipment, Net	68.0	$ 68.0
Reclassifications, Cash Flow Statement, Regulatory Assets, Use Of Cash	66.0
Reclassifications, Cash Flow Statement, Regulatory liabilities, Source of Cash	(5.0)
Reclassifications, Cash Flow Statement, Other assets, use of cash	(6.0)
Reclassifications, Cash Flow Statement, Derivative Financial Instruments, Source Of Cash	(100.0)
Reclassifications, Cash Flow Statement, Other Liabilities, Source Of Cash	$ 45.0
Genco
Significant Accounting Policies
Power Generation Capacity Megawatts | MW	605
Property, Plant and Equipment, Net	$ 483.0
PSNC Energy [Member]
Significant Accounting Policies
Percentage of natural gas inventory held by counterparties under asset management and supply service agreements (as a percent)	41.00%	46.00%
Natural gas inventory, carrying amount	$ 13.1	$ 17.7
PercentOfStorageFeesCreditedToRatePayers	75.00%

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RATE AND OTHER REGULATORY MATTERS (Details) $ in Millions	3 Months Ended		6 Months Ended	9 Months Ended		12 Months Ended
	Sep. 30, 2016 USD ($) MW	Sep. 30, 2015 USD ($)	Jun. 30, 2016 USD ($)	Sep. 30, 2016 USD ($) MW	Sep. 30, 2015 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2013
Rate Matters [Line Items]
Reclassifications, Cash Flow Statement, Regulatory Assets, Use Of Cash				$ 66.0
Carrying cost recovery				(12.0)	$ (9.0)
Regulatory Assets, Noncurrent	$ 2,202.0			$ 2,202.0		$ 1,937.0
MPG environmental remediation				18
SCEG
Rate Matters [Line Items]
Public Utilities changes in Retail Natural Gas Rates Approved under RSA				$ 4.1
Public Utilities, Percent Increase (Decrease) in Retail Natural Gas Rates				1.20%
Public Utilities, Rate Calculation Basis				12-month rolling average
Reclassifications, Cash Flow Statement, Regulatory Assets, Use Of Cash				$ 66.0
Capacity of renewable energy facilities by 2020 | MW	80			80
SCPSC Order Reduction Of Total Fuel Cost Component Of Retail Electric Rates To Reflect Lower Projected Fuel Costs And Eliminate Over-Collection Balances			$ 61.0
SCPSC Order, Recovery Of Projected DER Program Costs			6.9
Carrying costs on deferred income tax assets	$ 3.5	$ 2.4		$ 10.0	6.5
Carrying cost recovery				(12.0)	$ (9.0)
Regulatory Assets, Noncurrent	2,114.0			$ 2,114.0		$ 1,857.0
Demand side management recovery period				5
SCPSC Order, Annual DSM Program Rate Rider Recovery Amount			37.6
Increased Project Costs Above SCPSC Sept 2015 Order			852.0
Increased Project Costs Re Fixed Price Option			505.0
Revised Requested Project Costs above SCPSC Sept 2015 Order				$ 846.0
Estimated Gross Const Cost With Fixed Price Option			$ 7,700.0
Public Utilties increase (decrease) in retail electric rates				$ 64.4
Public Utilities Percentage Change in Retail Electric Rates Approved under BLRA				2.70%
Public Utilities, Authorized Allowable Return on Common Equity, Percentage				10.50%		0.00%
PSNC Energy
Rate Matters [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount				$ 19.1
Public Utilities, Approved Rate Increase (Decrease), Percentage				4.39%
Public Utilities, Authorized Allowable Return on Common Equity, Percentage				9.70%
Deferred Income Tax Charges [Member]
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	301.0			$ 301.0		$ 298.0
Regulatory Noncurrent Asset Amortization Period				85 years
Deferred Income Tax Charges [Member] | SCEG
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	294.0			$ 294.0		291.0
Asset Retirement Obligation Costs [Member]
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	402.0			$ 402.0		405.0
Regulatory Noncurrent Asset Amortization Period				110 years
Asset Retirement Obligation Costs [Member] | SCEG
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	380.0			$ 380.0		384.0
Environmental Restoration Costs [Member]
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	33.0			33.0		42.0
Environmental Restoration Costs [Member] | SCEG
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	26.0			26.0		35.0
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	63.0			63.0
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	14.0			14.0
Pension Costs [Member]
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	311.0			311.0		325.0
Pension Costs [Member] | SCEG
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	282.0			$ 282.0		295.0
Regulatory Noncurrent Asset Amortization Period				12 years
Other Regulatory Assets [Member]
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	173.0			$ 173.0		144.0
Regulatory Noncurrent Asset Amortization Period				30 years
Other Regulatory Assets [Member] | SCEG
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	$ 150.0			$ 150.0		$ 129.0

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RATE AND OTHER REGULATORY MATTERS (Details 2) $ in Millions	9 Months Ended
	Sep. 30, 2016 USD ($)	Dec. 31, 2015 USD ($)
Regulatory Assets
Regulatory Liabilities	$ 864	$ 855
Regulatory Assets, Noncurrent	2,202	1,937
SCEG
Regulatory Assets
Regulatory Liabilities	630	635
Regulatory Assets, Noncurrent	$ 2,114	1,857
Demand side management recovery period	5
Other Regulatory Liability [Member]
Regulatory Assets
Regulatory Liabilities	$ 28	27
Other Regulatory Liability [Member] | SCEG
Regulatory Assets
Regulatory Liabilities	17	20
Asset Retirement Obligation Costs [Member]
Regulatory Assets
Regulatory Liabilities	756	732
Asset Retirement Obligation Costs [Member] | SCEG
Regulatory Assets
Regulatory Liabilities	533	519
Deferred gains on interest rate derivatives [Member]
Regulatory Assets
Regulatory Liabilities	80	96
Deferred gains on interest rate derivatives [Member] | SCEG
Regulatory Assets
Regulatory Liabilities	80	96
Deferred Losses On Interest Rate Derivatives [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	791	535
Deferred Losses On Interest Rate Derivatives [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	791	535
Asset Retirement Obligation Costs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	402	405
Asset Retirement Obligation Costs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	380	384
unrecovered plant [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	119	127
unrecovered plant [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	119	127
Demand Side Management programs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	58	61
Demand Side Management programs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	58	61
Deferred costs uncertain tax position [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	14	0
Deferred Income Tax Charges [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	301	298
Deferred Income Tax Charges [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	294	291
Environmental Restoration Costs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	33	42
Environmental Restoration Costs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	26	35
Pension Costs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	311	325
Pension Costs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	282	295
Other Regulatory Assets [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	173	144
Other Regulatory Assets [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	$ 150	$ 129

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RATE AND OTHER REGULATORY MATTERS (Details 3) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Regulatory Liabilities [Line Items]
Regulatory Assets, Noncurrent	$ 2,202	$ 1,937
Regulatory Liabilities	864	855
SCEG
Regulatory Liabilities [Line Items]
Regulatory Assets, Noncurrent	2,114	1,857
Regulatory Liabilities	630	635
Asset Retirement Obligation Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	756	732
Asset Retirement Obligation Costs [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	533	519
Deferred gains on interest rate derivatives [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	80	96
Deferred gains on interest rate derivatives [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 80	$ 96

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COMMON EQUITY (Details) - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Schedule of Capitalization, Equity [Line Items]
Common Stock, Shares Authorized	200.0		200.0		200.0
COMMON EQUITY [Abstract]
Common Stock, Shares, Outstanding	142.9		142.9		142.9
SCEG
Schedule of Capitalization, Equity [Line Items]
Common Stock, Shares Authorized	50.0		50.0		50.0
COMMON EQUITY [Abstract]
Common Stock, Shares, Outstanding	40.3		40.3		40.3
Preferred Stock, Shares Authorized	20.0		20.0		20.0
Preferred Stock, Shares Outstanding	0.0		0.0		0.0
Commodity Contract
Schedule of Capitalization, Equity [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 0	$ (1)	$ (6)	$ (10)
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)	(6)	(6)
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	0	1	6	10
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	$ 6	$ 6

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LONG-TERM AND SHORT-TERM DEBT (Details) - USD ($) $ in Millions	Sep. 30, 2016	Jun. 30, 2016	Dec. 31, 2015
SCEG
Debt Instrument [Line Items]
First Mortgage Bonds		$ 425.0
Debt Instrument, Interest Rate, Stated Percentage		4.10%
Debt Instrument, Face Amount	$ 67.8		$ 67.8
Related Party Transaction, Due from (to) Related Party, Current	28.1		33.0
Due from Other Related Parties, Current			$ 9.0
PSNC Energy [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.13%
Senior Notes		$ 100.0
Nuclear Fuel Contract [Domain]
Debt Instrument [Line Items]
Long Term Contract for Nuclear Fuel Purchase	$ 100.0
Debt Instrument, Interest Rate, Stated Percentage	0.78%
First Mortgage Bonds [Member] | SCEG
Debt Instrument [Line Items]
First Mortgage Bonds		$ 75.0
Debt Instrument, Interest Rate, Stated Percentage		4.50%
first mortgage bond issued May 2014 [Member] | SCEG
Debt Instrument [Line Items]
First Mortgage Bonds	$ 300.0
Debt Instrument, Interest Rate, Stated Percentage	4.50%

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LONG-TERM AND SHORT-TERM DEBT (Details 2) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 2,000.0	$ 2,000.0
Commercial Paper	778.0	531.0
Letters of Credit Outstanding, Amount	3.3	3.3
Line of Credit Facility, Remaining Borrowing Capacity	1,219.0	1,465.0
3 Year Credit [Domain]
Debt Instrument [Line Items]
Long-term Line of Credit - SCE&G only	200.0	200.0
five year credit [Domain]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	1,300.0	1,300.0
SCANA [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	400.0	400.0
Commercial Paper	$ 16.0	$ 37.0
Debt, Weighted Average Interest Rate	0.93%	1.19%
Letters of Credit Outstanding, Amount	$ 3.0	$ 3.0
Line of Credit Facility, Remaining Borrowing Capacity	381.0	360.0
SCEG including Fuel Company [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	1,400.0	1,400.0
Commercial Paper	$ 714.0	$ 420.0
Debt, Weighted Average Interest Rate	0.84%	0.74%
Letters of Credit Outstanding, Amount	$ 0.3	$ 0.3
Line of Credit Facility, Remaining Borrowing Capacity	686.0	980.0
Fuel Company [Member]
Debt Instrument [Line Items]
Long-Term Line of Credit - SC Fuel Co only	500.0	500.0
SCEG
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	700.0	700.0
Long-term Line of Credit - SCE&G only	200.0	200.0
PSNC Energy [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	200.0	200.0
Commercial Paper	$ 47.0	$ 74.0
Debt, Weighted Average Interest Rate	0.8295%	0.77%
Line of Credit Facility, Remaining Borrowing Capacity	$ 153.0	$ 126.0

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INCOME TAXES (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Mar. 31, 2017	Sep. 30, 2016	Dec. 31, 2015
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued		$ 276
Unrecognized Tax Benefits		254	$ 44
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		228
Significant (Increase) Decrease in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Upper Bound		$ 49
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent		4.00%
SCEG
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued		$ 276
Unrecognized Tax Benefits		254	$ 44
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		228
Significant (Increase) Decrease in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Upper Bound		$ 49
Scenario, Forecast [Member]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent	3.00%

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DERIVATIVE FINANCIAL INSTRUMENTS (Details)	9 Months Ended	12 Months Ended
	Sep. 30, 2016 USD ($) MMBTU	Dec. 31, 2015 MMBTU
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	60,400,414	58,229,980
Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	8,600,000	7,530,000
Retail Gas Marketing
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	11,781,000	7,869,000
Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	40,019,414	42,830,980
Commodity Contract
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	24,604,500	19,372,500
Commodity Contract | Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	8,600,000	7,530,000
Commodity Contract | Retail Gas Marketing
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	11,781,000	7,869,000
Commodity Contract | Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	4,223,500	3,973,500
Energy Related Derivative [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	35,795,914	38,857,480
Energy Related Derivative [Member] | Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	35,795,914	38,857,480
Energy Related Derivative [Member] | Basis Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure	1,028,115	1,842,048

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DERIVATIVE FINANCIAL INSTRUMENTS Fair Value on Balance Sheet (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 12.0	$ 31.0
Derivative Liability, Fair Value, Gross Liability	268.0	107.0
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset		15.0
Derivative Liability, Fair Value, Gross Liability	261.0	87.0
Commodity Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	6.0	1.0
Derivative Liability, Fair Value, Gross Liability	1.0	5.0
Other Energy Management Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	6.0	15.0
Derivative Liability, Fair Value, Gross Liability	6.0	15.0
Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	3.0
Derivative Liability, Fair Value, Gross Liability	43.0	37.0
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	115.6	120.0
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	39.0	28.0
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability		4.0
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	3.0
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	9.0	30.0
Derivative Liability, Fair Value, Gross Liability	225.0	69.0
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	1,285.0	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	47.0	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	172.0	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	3.0	1.0
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset
Derivative Liability, Fair Value, Gross Liability	4.0	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	2.0	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	2.0	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	4.0	11.0
Derivative Liability, Fair Value, Gross Liability		2.0
SCEG | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset		15.0
Derivative Liability, Fair Value, Gross Liability	234.0	65.0
SCEG | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	15.0	10.0
SCEG | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	36.4	36.4
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	14.0	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	219.0	55.0
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	1,285.0	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	47.0	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	$ 172.0	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

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DERIVATIVE FINANCIAL INSTRUMENTS On Income Statement (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Derivative [Line Items]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	$ (1.0)	$ (7.0)	$ (4.0)	$ (8.0)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	$ (2.0)	$ (3.0)	$ (12.0)	$ (16.0)
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant	insignificant	insignificant	insignificant
Commodity Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 0.0	$ 1.0	$ 6.0	$ 10.0
Commodity Contract | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	(2.0)	(4.0)	0.0	(5.0)
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	2.0	2.0	6.0	6.0
Interest Rate Contract [Member] | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	1.0	(3.0)	(4.0)	(3.0)
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	(24.0)	(116.0)	(268.0)	(79.0)
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	(1.0)	(3.0)	(6.0)	(3.0)
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	(1.0)	0.0	(1.0)	5.0
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			1.7
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	0.0	(1.0)	(6.0)	(10.0)
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			(6.6)
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)	(6.0)	(6.0)
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			1.9
Interest Expense [Member] | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred			2.3
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	$ (1.0)	$ (1.0)	$ (2.0)	$ (2.0)
SCEG
Derivative [Line Items]
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant	insignificant	insignificant	insignificant
SCEG | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	$ (24.0)	$ (116.0)	$ (268.0)	$ (79.0)
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	(1.0)	(3.0)	(6.0)	(3.0)
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	(1.0)	0.0	(1.0)	5.0
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			1.9
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			2.3
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	$ (1.0)	$ (1.0)	$ (2.0)	$ (2.0)

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DERIVATIVE FINANCIAL INSTRUMENTS Derivative Financial Instruments (Credit Risk) (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Derivative [Line Items]
LetterofCreditAvailableCommodityDerivativesassetposition	$ 3.0	$ 3.0
Derivative, Net Asset Position, Aggregate Fair Value	6.0	14.0
Collateral Already Posted, Aggregate Fair Value	171.5	50.4
Additional Collateral, Aggregate Fair Value	91.8	44.8
Derivative, Net Liability Position, Aggregate Fair Value	263.3	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	140.4	13.4
Additional Collateral, Aggregate Fair Value	93.8	43.6
Derivative, Net Liability Position, Aggregate Fair Value	234.2	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

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DERIVATIVE FINANCIAL INSTRUMENTS Derivative Financial Instruments Offsetting Assets and Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 12	$ 31
Derivative Asset, Fair Value, Gross Liability	(2)	(1)
Derivative Asset	10	30
Derivative Liability, Fair Value, Gross Liability	268	107
Derivative Liability, Fair Value, Gross Asset	(2)	(1)
Derivative, Collateral, Right to Reclaim Securities	0	(8)
Derivative, Collateral, Right to Reclaim Cash	(171)	(50)
Derivative Liability, Fair Value, Amount Offset Against Collateral	95	48
Derivative Liability	266	106
Derivative, Collateral, Obligation to Return Securities	0	(8)
Derivative, Collateral, Obligation to Return Cash	0	0
Derivative Asset, Fair Value, Amount Offset Against Collateral	10	22
Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	2	8
Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset	8	22
Derivative Liability		3
Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	53	50
Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability	213	53
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset		15
Derivative Asset		15
Derivative Liability, Fair Value, Gross Liability	261	87
Derivative, Collateral, Right to Reclaim Securities		(8)
Derivative, Collateral, Right to Reclaim Cash	(169)	(36)
Derivative Liability, Fair Value, Amount Offset Against Collateral	92	43
Derivative Liability	261	87
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	6	1
Derivative Asset, Fair Value, Gross Liability	(1)
Derivative Asset	5	1
Derivative Liability, Fair Value, Gross Liability	1	5
Derivative Liability, Fair Value, Gross Asset	(1)
Derivative, Collateral, Right to Reclaim Cash		(5)
Derivative Liability, Fair Value, Amount Offset Against Collateral	0	0
Derivative Liability	0	5
Derivative Asset, Fair Value, Amount Offset Against Collateral	5	1
Other Energy Management Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	6	15
Derivative Asset, Fair Value, Gross Liability	(1)	(1)
Derivative Asset	5	14
Derivative Liability, Fair Value, Gross Liability	6	15
Derivative Liability, Fair Value, Gross Asset	(1)	(1)
Derivative, Collateral, Right to Reclaim Cash	(2)	(9)
Derivative Liability, Fair Value, Amount Offset Against Collateral	3	5
Derivative Liability	5	14
Derivative Asset, Fair Value, Amount Offset Against Collateral	5	14
SCEG
Derivative [Line Items]
Derivative Asset		15
Derivative Liability	234	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	48	34
SCEG | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability	186	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	234	65
Derivative, Collateral, Right to Reclaim Securities		(8)
Derivative, Collateral, Right to Reclaim Cash	(140)	(13)
Derivative Liability, Fair Value, Amount Offset Against Collateral	94	44
Derivative Liability	$ 234	65
Derivative, Collateral, Obligation to Return Securities		(8)
Derivative Asset, Fair Value, Amount Offset Against Collateral		$ 7

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FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Available-for-sale Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	$ 14	$ 11
Held-to-maturity Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	7
Interest Rate Contract | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure		15
Liabilities, Fair Value Disclosure	261	87
Commodity Contract | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	6	1
Liabilities, Fair Value Disclosure	1	1
Commodity Contract | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, Fair Value Disclosure		4
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]
Assets, Fair Value Disclosure	1
Liabilities, Fair Value Disclosure		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]
Assets, Fair Value Disclosure	5	14
Liabilities, Fair Value Disclosure	9	12
SCEG | Interest Rate Contract | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure		15
Liabilities, Fair Value Disclosure	$ 234	$ 65

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FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details 2) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	$ 6,588.6	$ 5,997.6
Long-term Debt, Fair Value	7,674.0	6,445.7
SCEG
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	5,264.9	4,769.0
Long-term Debt, Fair Value	$ 6,189.1	$ 5,129.1

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EMPLOYEE BENEFIT PLANS (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Pension and Other Postretirement Benefit Plans
Pension Contributions			No
Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	$ 4.4	$ 6.6	$ 15.5	$ 18.1
Interest cost	9.8	9.6	29.5	28.7
Expected return on assets	(13.8)	(15.5)	(41.9)	(46.5)
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	3.0	3.0
Defined Benefit Plan, Actuarial Net (Gains) Losses	3.7	3.2	11.1	10.2
Defined Benefit Plan, Net Periodic Benefit Cost	5.1	4.9	17.2	13.5
Other Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	0.8	1.2	3.3	4.0
Interest cost	3.0	2.8	9.1	8.6
Expected return on assets	0.0	0.0	0.0	0.0
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	0.1	0.1	0.2	0.3
Defined Benefit Plan, Actuarial Net (Gains) Losses	0.2	0.4	0.4	1.5
Defined Benefit Plan, Net Periodic Benefit Cost	4.1	4.5	$ 13.0	14.4
SCEG
Pension and Other Postretirement Benefit Plans
Pension Contributions			No
SCEG | Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	3.6	5.3	$ 12.7	14.5
Interest cost	8.3	8.1	25.0	24.1
Expected return on assets	(11.7)	(13.0)	(35.5)	(39.1)
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	2.5	2.5
Defined Benefit Plan, Actuarial Net (Gains) Losses	3.2	2.7	9.4	8.6
Defined Benefit Plan, Net Periodic Benefit Cost	4.2	3.9	14.1	10.6
SCEG | Other Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	0.7	1.0	2.7	3.2
Interest cost	2.5	2.2	7.5	6.8
Expected return on assets	0.0	0.0	0.0	0.0
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	0.1	0.1	0.2	0.2
Defined Benefit Plan, Actuarial Net (Gains) Losses	0.1	0.3	0.3	1.2
Defined Benefit Plan, Net Periodic Benefit Cost	$ 3.4	$ 3.6	$ 10.7	$ 11.4

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COMMITMENTS AND CONTINGENCIES (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2016 USD ($)	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Environmental
Goal For Reduced Carbon Dioxide Emissions From 2005 Levels By 2030 Under Clean Air Act	32.00%
NPDES permit renewal permit period	five
Nuclear Generation
Forecasted Incremental Capital Costs Associated With Schedule Delays, 2015 Petition	$ 539,000
EPC Contract Amendment, New Nuclear Construction Completion Bonus	151,000
EPC Contract Amendment, Payment and Performance Bonds	$ 45,000
EPC Contract Amendment, Payment And Performance Bonds, Percentage of Billing	15.00%
EPC Contract Amendment, Payment And Performance Bonds, Maximum Aggregate Nominal Coverage	$ 100,000
Dispute Review Board Resolution Without Recourse	less than $5 million
Dispute Review Board Resolution Subject To Litigation	greater than $5 million
SCEG
Commitments and contingencies
Storm Damage Provision	$ 2,000
Nuclear Insurance
Maximum liability assessment per reactor for each nuclear incident	127,300
Maximum Insurance Coverage For Each Nuclear Plant by ANI	375,000
Federal Limit on Public Liability Claims from Nuclear Incident Approximate	13,400,000
Maximum Federal Limit on Public Liability Claims Per Reactor for Each Year	18,900
Maximum Federal Limit on Public Liability Claims per Reactor for each Nuclear Incident at 2/3	84,800
Maximum Federal Limit on Public Liability Claims Per Incident for Each Year	$ 12,600
Inflation adjustment period for nuclear insurance	5
Maximum loss for a single nuclear incident	$ 2,750,000
NEIL Maximum Insurance Coverage of Accidental Property Damage	500,000
NEIL Maximum Insurance Coverage To Nuclear Facility For Property Damage And Outage Costs From Non-Nuclear Event	2,330,000
EMANI Maximum Retrospective Premium Assessment	1,800
EMANI Maximum Insurance Coverage for Summer Station Unit 1 For Property Damage And Outage Costs From Non-Nuclear Event	415,000
NEIL Maximum Prosepective Insurance Premium Per Nuclear Incident	45,800
NEIL Maximum Insurance Coverage to Nuclear Facility for Property Damage and Outage Costs	2,750,000
Environmental
Environmental Remediation Costs Recognized in Regulatory Assets	$ 26,000
Number of MGP decommissioned sites that contain residues of byproduct chemicals	4
Number Of States Required To Reduce Emissions Under CSAPR	28
Site Contingency MGP Estimated Environmental Remediation Costs	$ 10,300
Nuclear Generation
EPC Contract Amendment, Increase In Fixed Component Of Contract Price	165,000
EPC Contract Amendment, Credit Applied To Target Component Of New Units Contract Price	27,000
EPC Contract Amendment, Cap On Delay Oriented Liquidated Damages Per New Nuclear Unit	255,000
EPC Contract Amendment, Revised Construction Milestone Payment Schedule, Per Month	55,000
EPC Contract Amendment, Payment and Performance Bonds	25,000
EPC Contract Amendment, Payment And Performance Bonds, Maximum Aggregate Nominal Coverage	55,000
Transmission Capital Costs Forecast WIthdrawn	4,300
Total New Nuclear Project Cost Approved By SCPSC In September 2015	6,800,000
EPC Contract Amendment, Total New Nuclear Project Cost Including Amendment Increase	$ 7,200,000
SCEG
Nuclear Insurance
Jointly Owned Utility Plant, Proportionate Ownership Share	5.00%
Nuclear Generation
EPC Contract Amendment, Cap On Delay Oriented Liquidated Damages Per New Nuclear Unit	$ 186,000
EPC Contract Amendment, New Nuclear Construction Completion Bonus	83,000
EPC Contract Amendment, Fixed Price Option, Price For New Nuclear Construction After June 2015	3,345,000
EPC Contract Amendment, Increase In Fixed Component Of Contract Price, Payments	103,100
EPC Contract Amendment, Revised Construction Milestone Payment Schedule, Payments	$ 512,000
Summer Station New Units [Domain]
Nuclear Insurance
Jointly Owned Utility Plant, Proportionate Ownership Share	55.00%
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	$ 4,200,000
Nuclear Generation
jointly owned utility plant ownership, construction financing cost	3,200,000
EPC Contract Amendment, Increase In Fixed Component Of Contract Price	300,000
EPC Contract Amendment, Credit Applied To Target Component Of New Units Contract Price	50,000
EPC Contract Amendment, Cap On Delay Oriented Liquidated Damages Per New Nuclear Unit	463,000
EPC Contract Amendment, Fixed Price Option, New Nuclear Construction Completion Bonus	150,000
EPC Contract Amendment, New Nuclear Construction Completion Bonus	275,000
EPC Contract Amendment, Revised Construction Milestone Payment Schedule, Per Month	100,000
Nuclear Production Tax Credits	$ 1,400,000
Nuclear Production Tax Credit realization period	8
EPC Contract Amendment, Fixed Price Option, Price For New Nuclear Construction After June 2015	$ 6,082,000
EPC Contract Amendment, Fixed Price Option, Cap On Delay Oriented Liquidated Damages Per New Nuclear Unit	338,000
EPC Contract Amendment, Increase In Fixed Component Of Contract Price, Payments	188,000
EPC Contract Amendment, Revised Construction Milestone Payment Schedule, Payments	930,000
Capital costs, owners [Domain]
Nuclear Generation
Forecasted incremental capital costs, 2015 petition	245,000
Forecasted Total Capital Costs, 2015 Petition	5,200,000
Forecasted Gross Capital Costs, 2015 Petition	6,800,000
Capital costs, Other [Domain] [Domain]
Nuclear Generation
Forecasted incremental capital costs, 2015 petition	453,000
Scenario, Forecast [Member] | SCEG
Nuclear Generation
Additional ownership in new units		2.00%	2.00%	1.00%
Maximum [Member] | SCEG
Nuclear Generation
Additional ownership in new units, dollars	$ 850,000

XML

SEGMENT OF BUSINESS INFORMATION (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Segment Reporting Information [Line Items]
Gain (Loss) On Disposition Of Regulated Business Net Of Transaction Costs	$ 0	$ 0	$ 0	$ 235
Gain (Loss) on Disposition of Nonregulated Business, Net of Transaction Costs				202
Electric Domestic Regulated Revenue	817	742	2,035	2,008
Revenues	0	0	0	0
Net Income (Loss) Available to Common Stockholders, Basic	189	149	471	648
Operating Income	(348)	(292)	(900)	(1,095)
Regulated Operating Revenue, Gas	111	112	538	610
Regulated and Unregulated Operating Revenue	1,093	1,068	3,171	3,423
Segment Assets	18,446		18,446		$ 17,146
Electric Operations
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue	817	742	2,035	2,008
Revenues	1	1	4	4
Operating Income	(364)	(313)	(784)	(728)
Segment Assets	11,543		11,543		10,883
Gas Distribution
Segment Reporting Information [Line Items]
Revenues	0	2	1	2
Operating Income	14	13	(79)	(88)
Regulated and Unregulated Operating Revenue	111	112	538	609
Segment Assets	2,757		2,757		2,606
Retail Gas Marketing
Segment Reporting Information [Line Items]
Revenues	0	0	0	0
Net Income (Loss) Available to Common Stockholders, Basic	(3)	(3)	17	18
Regulated and Unregulated Operating Revenue	68	68	315	344
Segment Assets	140		140		106
Energy Marketing [Member]
Segment Reporting Information [Line Items]
Revenues	35	34	83	101
Net Income (Loss) Available to Common Stockholders, Basic	2	(1)	6	8
Regulated and Unregulated Operating Revenue	97	146	283	461
Segment Assets	58		58		95
All Other [member]
Segment Reporting Information [Line Items]
Revenues	100	102	302	309
Net Income (Loss) Available to Common Stockholders, Basic	(7)	(9)	(14)	188
Operating Income	0	0	0	(237)
Regulated and Unregulated Operating Revenue	0	0	0	5
Segment Assets	985		985		998
Adjustments/Eliminations
Segment Reporting Information [Line Items]
Revenues	(136)	(139)	(390)	(416)
Net Income (Loss) Available to Common Stockholders, Basic	197	162	462	434
Operating Income	(2)	8	37	(42)
Regulated and Unregulated Operating Revenue	0	0	0	(4)
Segment Assets	2,963		2,963		2,458
SCEG
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue	818	743	2,039	2,013
Operating Income	(359)	(307)	(816)	(763)
Regulated Operating Revenue, Gas	64	63	253	275
Net Income (Loss) Attributable to Parent	201	164	423	394
Segment Assets	15,978		15,978		14,765
Regulated Operating Revenue	882	806	2,292	2,288
SCEG | Electric Operations
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue	818	743	2,039	2,013
Operating Income	(364)	(313)	(784)	(728)
Segment Assets	11,543		11,543		10,883
SCEG | Gas Distribution
Segment Reporting Information [Line Items]
Operating Income	5	6	(32)	(35)
Regulated and Unregulated Operating Revenue	64	63	253	275
Segment Assets	801		801		757
SCEG | Adjustments/Eliminations
Segment Reporting Information [Line Items]
Operating Income	0	0	0	0
Regulated and Unregulated Operating Revenue	0	0	0	0
Net Income (Loss) Attributable to Parent	201	$ 164	423	$ 394
Segment Assets	$ 3,634		$ 3,634		$ 3,125

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AFFILIATED TRANSACTIONS (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Mar. 31, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Canadys Refined Coal [Member]
Affiliated Transactions [Line Items]
Equity Method Investment, Ownership Percentage	40.00%			40.00%
Related Party Transaction, Purchases from Related Party	$ 41.8	$ 66.3		$ 138.6	$ 186.0
Sales to Affiliate	41.6	65.9		137.8	185.1
Related Party Tax Expense, Due from Affiliates, Current				4.0		$ 12.8
Related Party Tax Expense, Due to Affiliates, Current				4.1		12.9
Carolina Gas Transmission [Member]
Affiliated Transactions [Line Items]
Related Party Transaction, Purchases from Related Party			$ 3.4
Energy Marketing [Member]
Affiliated Transactions [Line Items]
Due to Affiliate, Current	10.9			10.9		7.5
Cost of Natural Gas Purchases	34.8	34.0		83.1	101.4
SCANA Services [Member]
Affiliated Transactions [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	80.4	$ 80.8		236.4	$ 226.0
Accounts Payable, Related Parties, Current	50.8			50.8		57.0
SCEG
Affiliated Transactions [Line Items]
Due to Affiliate, Current	95.0			95.0		113.0
Due from Affiliate, Current	$ 4.0			$ 4.0		$ 22.0