10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2017

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, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and "emerging growth 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	Emerging growth company  o
South Carolina Electric & Gas Company	Large accelerated filer  o	Accelerated filer  o	Non-accelerated filer  x	Smaller reporting company  o	Emerging growth company  o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

SCANA Corporation o     South Carolina Electric & Gas Company o

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

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

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

	Description of	Shares Outstanding
Registrant	Common Stock	at April 30, 2017
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 Comprehensive Income	14
		Condensed Consolidated Statements of Cash Flows	15
		Condensed Consolidated Statements of Changes in Equity	16
	Notes to Condensed Consolidated Financial Statements		17
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations			39
Item 3. Quantitative and Qualitative Disclosures About Market Risk			43
Item 4. Controls and Procedures			44
PART II. OTHER INFORMATION
Item 1. Legal Proceedings			45
Item 1A. Risk Factors			45
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			54
Item 5. Other Information			55
Item 6. Exhibits			55
Signatures			56
Exhibit Index			57

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) uncertainty relating to the recent bankruptcy filing by the members of the Consortium building the New Units, including the effect of a rejection of the EPC Contract and the prudency and feasibility of completing the New Units; (2) the ability of SCANA and its subsidiaries (the Company) to recover through rates additional costs incurred in connection with the completion of the New Units or costs incurred to date in the event of the abandonment of one or both of the New Units; (3) continuing uncertainties as to future construction delays and cost overruns in connection with the completion of construction of the New Units, including delays and cost overruns resulting from the bankruptcy of members of the Consortium; (4) the ability of the Company to recover amounts which may become due from the Consortium or from Toshiba under its payment guaranty; (5) maintaining creditworthy joint owners (including possible new or different joint owners) for SCE&G’s new nuclear generation project; (6) the creditworthiness and/or financial stability of contractors and other providers of design and engineering services for SCE&G's new nuclear generation project; (7) changes in tax laws and realization of tax benefits and credits, including production tax credits for new nuclear units, and the ability or inability to realize credits and deductions, particularly in light of construction delays which have occurred or may occur with respect to the New Units; (8) the information is of a preliminary nature and may be subject to further and/or continuing review and adjustment; (9) legislative and regulatory actions, particularly changes related to electric and gas services, rate regulation, regulations governing electric grid reliability and pipeline integrity, environmental regulations, the BLRA, and actions affecting the construction and possible abandonment of one or both of the New Units; (10) current and future litigation; (11) the results of short- and long-term financing efforts, including prospects for obtaining access to capital markets and other sources of liquidity, and the effect of rating agency actions on the Company’s cost of and access to capital and sources of liquidity; (12) the ability of suppliers, both domestic and international, to timely provide the labor, secure processes, components, parts, tools, equipment and other supplies needed which may be highly specialized or in short supply, at agreed upon quality and prices, for our construction program, operations and maintenance; (13) the results of efforts to ensure the physical and cyber security of key assets and processes; (14) changes in the economy, especially in areas served by subsidiaries of SCANA; (15) the impact of competition from other energy suppliers, including competition from alternate fuels in industrial markets; (16) the impact of conservation and demand side management efforts and/or technological advances on customer usage; (17) the loss of sales to distributed generation, such as solar photovoltaic systems or energy storage systems; (18) growth opportunities for SCANA’s regulated and other subsidiaries; (19) the effects of weather, especially in areas where the generation and transmission facilities of SCANA and its subsidiaries are located and in areas served by SCANA’s subsidiaries; (20) changes in SCANA’s or its subsidiaries’ accounting rules and accounting policies; (21) payment and performance by counterparties and customers as contracted and when due; (22) the results of efforts to license, site, construct and finance facilities, and to receive related rate recovery, for electric generation and transmission, including nuclear generating facilities;

(23) 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; (24) 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; (25) the availability of skilled, licensed and experienced human resources to properly manage, operate, and grow the Company’s businesses; (26) labor disputes; (27) performance of SCANA’s pension plan assets and the effect(s) of associated discount rates; (28) inflation or deflation; (29) changes in interest rates; (30) compliance with regulations; (31) natural disasters and man-made mishaps that directly affect our operations or the regulations governing them; and (32) 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
Bankruptcy Court	United States Bankruptcy Court for the Southern District of New York
BLRA	Base Load Review Act
CAA	Clean Air Act, as amended
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
CFTC	Commodity Futures Trading Commission
CO2	Carbon Dioxide
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 WECTEC
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
DER	Distributed Energy Resource
DHEC	South Carolina Department of Health and Environmental Control
Dodd-Frank	Dodd-Frank Wall Street Reform and Consumer Protection Act
DOE	United States Department of Energy
DRB	Dispute Resolution 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
EPA	United States Environmental Protection Agency
EPC Contract	Engineering, Procurement and Construction Agreement dated May 23, 2008, as amended by the October 2015 Amendment
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
Interim Assessment Agreement	Interim Assessment Agreement dated March 28, 2017, as amended, among SCE&G, Santee Cooper, WEC and WECTEC
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
LOC	Lines of Credit

4

MATS	Mercury and Air Toxics Standards
MGP	Manufactured Gas Plant
MMBTU	Million British Thermal Units
MW or MWh	Megawatt or Megawatt-hour
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
NOX	Nitrogen Oxide
NPDES	National Pollutant Discharge Elimination System
NRC	United States Nuclear Regulatory Commission
NSPS	New Source Performance Standards
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
PHMSA	United States Pipeline Hazardous Materials Safety Administration
Price-Anderson	Price-Anderson Indemnification Act
PSNC Energy	Public Service Company of North Carolina, Incorporated
Registrants	SCANA and SCE&G
ROE	Return on Equity
RSA	Natural Gas Rate Stabilization Act
RTO/ISO	Regional Transmission Organization/Independent System Operator
Santee Cooper	South Carolina Public Service Authority
SCANA	SCANA Corporation, the parent company
SCANA Energy	SCANA Energy Marketing, Inc.
SCANA Services	SCANA Services, Inc.
SCE&G	South Carolina Electric & Gas Company
SCEUC	South Carolina Energy Users Committee
SCPSC	Public Service Commission of South Carolina
SEC	United States Securities and Exchange Commission
SIP	State Implementation Plan
SO2	Sulfur Dioxide
Stone & Webster	Prior to December 31, 2015, Stone & Webster, Inc. and later becoming CB&I Stone & Webster, a subsidiary of CB&I; effective December 31, 2015, Stone & Webster, a subsidiary of WEC
Summer Station	V. C. Summer Nuclear Station
Supreme Court	United States Supreme Court
Toshiba	Toshiba Corporation, parent company of WEC
Unit 1	Nuclear Unit 1 at Summer Station
VIE	Variable Interest Entity
Vogtle Units	Two nuclear units being constructed by the Consortium for another group of utilities
WEC	Westinghouse Electric Company LLC
WECTEC	WECTEC Global Project Services, Inc. (formerly known as Stone & Webster), a wholly-owned subsidiary of WEC
Williams Station	A.M. Williams Generating Station, owned by GENCO
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	March 31, 2017			December 31, 2016
Assets
Utility Plant In Service	$	13,543		$	13,444
Accumulated Depreciation and Amortization	(4,494		)	(4,446		)
Construction Work in Progress	5,011			4,845
Nuclear Fuel, Net of Accumulated Amortization	265			271
Goodwill, net of writedown of $230	210			210
Utility Plant, Net	14,535			14,324
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation of $137 and $138	275			276
Assets held in trust, net-nuclear decommissioning	126			123
Other investments	77			76
Nonutility Property and Investments, Net	478			475
Current Assets:
Cash and cash equivalents	12			208
Receivables:
Customer, net of allowance for uncollectible accounts of $6 and $6	549			616
Income taxes	6			142
Other	94			127
Inventories (at average cost):
Fuel and gas supply	114			136
Materials and supplies	153			155
Prepayments	103			105
Other current assets	16			17
Total Current Assets	1,047			1,506
Deferred Debits and Other Assets:
Regulatory assets	2,128			2,130
Other	270			272
Total Deferred Debits and Other Assets	2,398			2,402
Total	$	18,458		$	18,707

See Notes to Condensed Consolidated Financial Statements.

6

Millions of dollars	March 31, 2017			December 31, 2016
Capitalization and Liabilities
Common Stock - no par value, 142.9 million shares outstanding	$	2,389		$	2,390
Retained Earnings	3,468			3,384
Accumulated Other Comprehensive Loss	(51		)	(49		)
Total Common Equity	5,806			5,725
Long-Term Debt, net	6,466			6,473
Total Capitalization	12,272			12,198
Current Liabilities:
Short-term borrowings	869			941
Current portion of long-term debt	17			17
Accounts payable	269			404
Customer deposits and customer prepayments	158			168
Taxes accrued	59			201
Interest accrued	92			84
Dividends declared	85			80
Derivative financial instruments	27			35
Other	85			135
Total Current Liabilities	1,661			2,065
Deferred Credits and Other Liabilities:
Deferred income taxes, net	2,184			2,159
Asset retirement obligations	562			558
Pension and other postretirement benefits	375			373
Unrecognized tax benefits	274			219
Regulatory liabilities	938			930
Other	192			205
Total Deferred Credits and Other Liabilities	4,525			4,444
Commitments and Contingencies (Note 9)
Total	$	18,458		$	18,707

See Notes to Condensed Consolidated Financial Statements.

7

SCANA Corporation and Subsidiaries

Condensed Consolidated Statements of Income

(Unaudited)

	Three Months Ended
	March 31,
Millions of dollars, except per share amounts	2017			2016
Operating Revenues:
Electric	$	577		$	592
Gas - regulated	322			299
Gas - nonregulated	274			281
Total Operating Revenues	1,173			1,172
Operating Expenses:
Fuel used in electric generation	136			136
Purchased power	11			11
Gas purchased for resale	370			359
Other operation and maintenance	179			181
Depreciation and amortization	95			91
Other taxes	66			63
Total Operating Expenses	857			841
Operating Income	316			331
Other Income (Expense):
Other income	17			16
Other expense	(10		)	(14		)
Interest charges, net of allowance for borrowed funds used during construction of $6 and $4	(87		)	(83		)
Allowance for equity funds used during construction	9			5
Total Other Expense	(71		)	(76		)
Income Before Income Tax Expense	245			255
Income Tax Expense	74			79
Net Income	$	171		$	176
Earnings Per Share of Common Stock	$	1.19		$	1.23
Weighted Average Common Shares Outstanding (millions)	142.9			142.9
Dividends Declared Per Share of Common Stock	$	0.6125		$	0.575

See Notes to Condensed Consolidated Financial Statements.

8

SCANA Corporation and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income

(Unaudited) 

	Three Months Ended March 31,
Millions of dollars	2017			2016
Net Income	$	171		$	176
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 $(1) and $(3)	(2		)	(5		)
Cash flow hedging activities reclassified to interest expense, net of tax of $1 and $1	2			2
Cash flow hedging activities reclassified to gas purchased for resale, net of tax of $(1) and $3	(2		)	5
Net unrealized gains (losses) on cash flow hedging activities	(2		)	2
Other Comprehensive Income (Loss)	(2		)	2
Total Comprehensive Income	$	169		$	178

See Notes to Condensed Consolidated Financial Statements.

9

SCANA Corporation and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(Unaudited) 

	Three Months Ended March 31,
Millions of dollars	2017			2016
Cash Flows From Operating Activities:
Net income	$	171		$	176
Adjustments to reconcile net income to net cash provided from operating activities:
Deferred income taxes, net	27			(11		)
Depreciation and amortization	100			94
Amortization of nuclear fuel	14			14
Allowance for equity funds used during construction	(9		)	(5		)
Carrying cost recovery	(5		)	(4		)
Changes in certain assets and liabilities:
Receivables	67			—
Income taxes receivable	136			—
Inventories	6			11
Prepayments	(5		)	(11		)
Regulatory assets	(4		)	—
Regulatory liabilities	(3		)	(1		)
Accounts payable	(48		)	(39		)
Unrecognized tax benefits	55			—
Taxes accrued	(142		)	(159		)
Derivative financial instruments	(3		)	(3		)
Other assets	(2		)	(20		)
Other liabilities	(46		)	19
Net Cash Provided From Operating Activities	309			61
Cash Flows From Investing Activities:
Property additions and construction expenditures	(342		)	(385		)
Proceeds from investments (including derivative collateral returned)	19			198
Purchase of investments (including derivative collateral posted)	(20		)	(264		)
Net Cash Used For Investing Activities	(343		)	(451		)
Cash Flows From Financing Activities:
Repayment of long-term debt	(8		)	(8		)
Dividends	(82		)	(78		)
Short-term borrowings, net	(72		)	386
Net Cash Provided From (Used For) Financing Activities	(162		)	300
Net Decrease In Cash and Cash Equivalents	(196		)	(90		)
Cash and Cash Equivalents, January 1	208			176
Cash and Cash Equivalents, March 31	$	12		$	86
Supplemental Cash Flow Information:
Cash for–Interest paid (net of capitalized interest of $6 and $4)	$	76		$	77
–Income taxes paid	—			141
–Income taxes received	123			—
Noncash Investing and Financing Activities:
Accrued construction expenditures	57			142
Capital leases	—			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, 2017	143	$	2,402	$	(12	)	$	3,384		$	(36	)	$	(13	)	$	(49	)	$	5,725
Net Income							171												171
Other Comprehensive Income (Loss)
Losses arising during the period										(2		)	—			(2		)	(2		)
Losses/amortization reclassified from AOCI										—			—			—			—
Total Comprehensive Income							171			(2		)	—			(2		)	169
Purchase of Treasury Stock	—	—		(1		)													(1		)
Dividends Declared							(87		)										(87		)
Balance as of March 31, 2017	143	$	2,402	$	(13	)	$	3,468		$	(38	)	$	(13	)	$	(51	)	$	5,806
Balance as of January 1, 2016	143	$	2,402	$	(12	)	$	3,118		$	(53	)	$	(12	)	$	(65	)	$	5,443
Net Income							176												176
Other Comprehensive Income (Loss)
Losses arising during the period										(5		)	—			(5		)	(5		)
Losses/amortization reclassified from AOCI										7			—			7			7
Total Comprehensive Income							176			2			—			2			178
Dividends Declared							(82		)										(82		)
Balance as of March 31, 2016	143	$	2,402	$	(12	)	$	3,212		$	(51	)	$	(12	)	$	(63	)	$	5,539

Dividends declared per share of common stock were $0.6125 and $0.575 for March 31, 2017 and 2016, respectively.

See Notes to Condensed Consolidated Financial Statements.

11

South Carolina Electric & Gas Company and Affiliates

Condensed Consolidated Balance Sheets

(Unaudited)

Millions of dollars	March 31, 2017			December 31, 2016
Assets
Utility Plant In Service	$	11,588		$	11,510
Accumulated Depreciation and Amortization	(4,032		)	(3,991		)
Construction Work in Progress	4,950			4,813
Nuclear Fuel, Net of Accumulated Amortization	265			271
Utility Plant, Net ($752 and $756 related to VIEs)	12,771			12,603
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	69			69
Assets held in trust, net-nuclear decommissioning	126			123
Other investments	3			3
Nonutility Property and Investments, Net	198			195
Current Assets:
Cash and cash equivalents	11			164
Receivables:
Customer, net of allowance for uncollectible accounts of $3 and $3	328			378
Affiliated companies	14			16
Income taxes	—			53
Other	66			94
Inventories (at average cost):
Fuel	78			83
Materials and supplies	143			143
Prepayments	88			88
Other current assets	2			1
Total Current Assets ($74 and $85 related to VIEs)	730			1,020
Deferred Debits and Other Assets:
Regulatory assets	2,026			2,030
Other	240			243
Total Deferred Debits and Other Assets ($48 and $52 related to VIEs)	2,266			2,273
Total	$	15,965		$	16,091

See Notes to Condensed Consolidated Financial Statements.

12

Millions of dollars	March 31, 2017			December 31, 2016
Capitalization and Liabilities
Common Stock - no par value, 40.3 million shares outstanding	$	2,860		$	2,860
Retained Earnings	2,513			2,481
Accumulated Other Comprehensive Loss	(3		)	(3		)
Total Common Equity	5,370			5,338
Noncontrolling Interest	135			134
Total Equity	5,505			5,472
Long-Term Debt, net	5,147			5,154
Total Capitalization	10,652			10,626
Current Liabilities:
Short-term borrowings	770			804
Current portion of long-term debt	12			12
Accounts payable	152			247
Affiliated payables	100			122
Customer deposits and customer prepayments	114			126
Taxes accrued	102			195
Interest accrued	72			68
Dividends declared	79			79
Derivative financial instruments	23			28
Other	37			55
Total Current Liabilities	1,461			1,736
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,951			1,939
Asset retirement obligations	526			522
Pension and other postretirement benefits	234			232
Unrecognized tax benefits	333			236
Regulatory liabilities	705			695
Other	88			89
Other affiliate	15			16
Total Deferred Credits and Other Liabilities	3,852			3,729
Commitments and Contingencies (Note 9)
Total	$	15,965		$	16,091

See Notes to Condensed Consolidated Financial Statements.

13

South Carolina Electric & Gas Company and Affiliates

Condensed Consolidated Statements of Comprehensive Income

(Unaudited) 

	Three Months Ended
	March 31,
Millions of dollars	2017			2016
Operating Revenues:
Electric	$	577		$	592
Electric - nonconsolidated affiliate	1			1
Gas	141			124
Total Operating Revenues	719			717
Operating Expenses:
Fuel used in electric generation	112			119
Fuel used in electric generation - nonconsolidated affiliate	24			17
Purchased power	11			11
Gas purchased for resale	66			50
Gas purchased for resale - nonconsolidated affiliate	—			6
Other operation and maintenance	101			96
Other operation and maintenance - nonconsolidated affiliate	45			50
Depreciation and amortization	77			74
Other taxes	60			56
Other taxes - nonconsolidated affiliate	1			2
Total Operating Expenses	497			481
Operating Income	222			236
Other Income (Expense):
Other income	8			5
Other expense	(6		)	(8		)
Interest charges, net of allowance for borrowed funds used during construction of $6 and $3	(69		)	(66		)
Allowance for equity funds used during construction	9			5
Total Other Income (Expense)	(58		)	(64		)
Income Before Income Tax Expense	164			172
Income Tax Expense	52			56
Net Income and Total Comprehensive Income	112			116
Less Net Income and Total Comprehensive Income Attributable to Noncontrolling Interest	(3		)	(3		)
Earnings and Comprehensive Income Available to Common Shareholder	$	109		$	113
Dividends Declared on Common Stock	$	79		$	74

See Notes to Condensed Consolidated Financial Statements.

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South Carolina Electric & Gas Company and Affiliates

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	Three Months Ended March 31,
Millions of dollars	2017			2016
Cash Flows From Operating Activities:
Net income	$	112		$	116
Adjustments to reconcile net income to net cash provided from operating activities:
Deferred income taxes, net	12			(15		)
Depreciation and amortization	79			76
Amortization of nuclear fuel	14			14
Allowance for equity funds used during construction	(9		)	(5		)
Carrying cost recovery	(5		)	(4		)
Changes in certain assets and liabilities:
Receivables	45			7
Receivables - affiliate	2			(2		)
Income tax receivable	53			—
Inventories	(7		)	(3		)
Prepayments	—			(3		)
Regulatory assets	(2		)	2
Regulatory liabilities	—			(1		)
Accounts payable	(11		)	(23		)
Accounts payable - affiliate	(21		)	(8		)
Taxes accrued	(93		)	(223		)
Unrecognized tax benefit	97			—
Other assets	1			(8		)
Other liabilities	(14		)	25
Net Cash Provided From (Used For) Operating Activities	253			(55		)
Cash Flows From Investing Activities:
Property additions and construction expenditures	(282		)	(337		)
Proceeds from investments (including derivative collateral returned)	10			171
Purchase of investments (including derivative collateral posted)	(12		)	(239		)
Proceeds from money pool investments	—			9
Net Cash Used For Investing Activities	(284		)	(396		)
Cash Flows From Financing Activities:
Repayment of long-term debt	(8		)	(8		)
Dividends	(79		)	(75		)
Money pool borrowings, net	(1		)	11
Short-term borrowings, net	(34		)	450
Net Cash Provided From (Used for) Financing Activities	(122		)	378
Net Decrease In Cash and Cash Equivalents	(153		)	(73		)
Cash and Cash Equivalents, January 1	164			130
Cash and Cash Equivalents, March 31	$	11		$	57
Supplemental Cash Flow Information:
Cash for–Interest (net of capitalized interest of $6 and $3)	$	61		$	63
– Income taxes paid	3			175
– Income taxes received	143			7
Noncash Investing and Financing Activities:
Accrued construction expenditures	46			109
Capital leases	—			5

See Notes to Condensed Consolidated Financial Statements.

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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, 2017	40	$	2,860	$	2,481		$	(3	)	$	134		$	5,472
Earnings available to common shareholder				109						3			112
Total Comprehensive Income				109			—			3			112
Cash dividend declared				(77		)				(2		)	(79		)
Balance at March 31, 2017	40	$	2,860	$	2,513		$	(3	)	$	135		$	5,505
Balance at January 1, 2016	40	$	2,760	$	2,265		$	(3	)	$	129		$	5,151
Earnings available to common shareholder				113						3			116
Total Comprehensive Income				113			—			3			116
Cash dividend declared				(72		)				(2		)	(74		)
Balance at March 31, 2016	40	$	2,760	$	2,306		$	(3	)	$	130		$	5,193

See Notes to Condensed Consolidated Financial Statements.

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SCANA Corporation and Subsidiaries

South Carolina Electric & Gas Company and Affiliates

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, 2016, which also were a combined presentation. 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 and Condensed Consolidated Statements of Comprehensive Income are not necessarily indicative of amounts expected for the full year.  In the opinion of management of the respective companies, 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 $487 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, the retail natural gas marketing business (including those activities of segments described in Note 10) are presented within Operating Income, and all other activities are presented 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, 29% and 40% of PSNC Energy’s natural gas inventory at March 31, 2017 and December 31, 2016, respectively, with a carrying value of $4.2 million and $9.8 million, respectively.  Under the terms of this agreement, PSNC Energy receives storage asset management feesof which 75% are credited to rate payers. This agreement expired on March 31, 2017, and was replaced with a similar agreement that expires on March 31, 2019.

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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.

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 analysis of contracts with customers to which the guidance might be applicable, particularly large customer contracts, has begun. In addition, activities of the FASB's Transition Resource Group for Revenue Recognition are being monitored, particularly as they relate to the required treatment under the standard of contributions in aid of construction, alternative revenue programs and the collectibility of revenue of utilities subject to rate regulation.

In July 2015, the FASB issued accounting guidance intended to simplify the measurement of inventory cost by requiring most inventory to be measured at the lower of cost and net realizable value. The Company and Consolidated SCE&G adopted this guidance in the first quarter of 2017 and the adoption of this guidance did not have any impact on their respective financial statements.

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

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

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

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

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

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

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

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In October 2016, the FASB issued accounting guidance related to the tax effects of intra-entity asset transfers of assets other than inventory. An entity will be required to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The Company and Consolidated SCE&G adopted this guidance in the first quarter 2017 and it had no impact on their respective financial statements.

In November 2016, the FASB issued accounting guidance related to the presentation of restricted cash on the statement of cash flows. The guidance is effective for years beginning in 2018, and the Company and Consolidated SCE&G do not anticipate that its adoption will impact their respective financial statements.

In January 2017, the FASB issued accounting guidance to simplify the accounting for goodwill impairment. The guidance removes Step 2 of the goodwill impairment test. The guidance is effective for years beginning in 2020, though early adoption after January 1, 2017 is allowed. The Company and Consolidated SCE&G have not determined when this guidance will be adopted but do not anticipate that its adoption will have a material impact on their respective financial statements.

In March 2017, the FASB issued accounting guidance to change the required presentation of net periodic pension and postretirement benefit cost. Under the new guidance, the net periodic pension and postretirement benefit cost are to be separated into their service cost components and other components. The service cost components are to be presented in the same line item (or items) as other compensation costs arising from services rendered by employees during the period. The other components are to be reported in the income statement separately from the service cost component and outside operating income. Only the service cost component is eligible for capitalization in assets. This guidance is required to be applied on a retrospective basis for the presentation of the service cost component and the other components of net benefit cost and on a prospective basis for the capitalization of only the service cost component of net benefit cost. The Company and Consolidated SCE&G will adopt the guidance when required in the first quarter of 2018 and have not determined what impact it will have on their respective financial statements.

2.RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric - Cost of Fuel

By order dated July 15, 2015, the SCPSC approved SCE&G's participation in a DER program and to recover related 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 27, 2017, the SCPSC approved a settlement agreement among SCE&G, ORS and SCEUC, to increase the total fuel cost component of retail electric rates. SCE&G agreed to set its base fuel component in such a manner as to produce a projected under recovery of $61.0 million over a 12-month period beginning with the first billing cycle of May 2017. SCE&G also agreed to recover, over a 12-month period beginning with the first billing cycle of May 2017, projected DER program costs of approximately $16.5 million. Additionally, deferral of carrying cost will be allowed for base fuel component under collected balances, as they occur.

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 months ended March 31, 2017 totaled $4.3 million. During the three months ended March 31, 2016, carrying costs totaled $3.1 million. SCE&G anticipates that when the New Units are placed in service and accelerated tax depreciation is recognized on them, these deferred income tax assets will decline. When these deferred income tax assets are fully offset by related deferred income tax liabilities, the carrying cost accruals will cease, and the regulatory asset will begin to be amortized.

By order dated March 1, 2017, the SCPSC approved SCE&G’s request to decrease its pension costs rider. The change in the pension rider will decrease annual revenue by approximately $11.9 million. The pension rider is designed to allow

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SCE&G to recover projected pension costs, net of the previously over-collected balance, over a 12-month period, beginning with the first billing cycle in May 2017.

In January 2017, SCE&G requested in its annual DSM Programs filing to recover $37.0 million of costs and net lost revenues associated with DSM programs, along with an incentive to invest in such programs. On April 27, 2017, the SCPSC approved SCE&G's request effective beginning with the first billing cycle in May 2017.

Gas - PSNC Energy

PSNC Energy was authorized to implement a tracker that provides for biannual rate adjustments to recover the revenue requirement associated with integrity management plant investment and associated costs incurred from prevailing federal standards for pipeline integrity and safety that are not otherwise included in current base rates. On February 15, 2017, PSNC Energy filed its first biannual application for an adjustment to its rates under the Integrity Management Tracker, requesting recovery of an annual revenue requirement of $1.9 million. The NCUC approved this request and the revised rates became effective for service rendered on and after March 1, 2017.

Regulatory Assets and Regulatory Liabilities

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

	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2017		December 31, 2016		March 31, 2017		December 31, 2016
Regulatory Assets:
Accumulated deferred income taxes	$	317	$	316	$	309	$	307
AROs and related funding	425		425		402		403
Deferred employee benefit plan costs	336		342		303		309
Deferred losses on interest rate derivatives	614		620		614		620
Unrecovered plant	113		117		113		117
DSM Programs	59		59		59		59
Carrying costs on deferred tax assets related to nuclear construction	37		32		37		32
Pipeline integrity management costs	37		33		6		6
Environmental remediation costs	31		32		25		26
Deferred storm damage costs	20		20		20		20
Deferred costs related to uncertain tax position	17		15		17		15
Other	122		119		121		116
Total Regulatory Assets	$	2,128	$	2,130	$	2,026	$	2,030

Regulatory Liabilities:
Asset removal costs	$	760	$	755	$	533	$	529
Deferred gains on interest rate derivatives	157		151		157		151
Other	21		24		15		15
Total Regulatory Liabilities	$	938	$	930	$	705	$	695

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

AROs and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Unit 1 and conditional AROs related to generation, transmission and distribution properties, including gas pipelines. These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 110 years.

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Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under GAAP. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. In 2013 SCE&G began recovering through utility rates approximately $63 million of deferred pension costs for electric operations over approximately 30 years and approximately $14 million of deferred pension costs for gas operations over approximately 14 years. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees, or up to approximately 11 years.

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

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

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. 

Carrying costs on deferred tax assets related to nuclear construction are calculated on accumulated deferred income tax assets associated with the New Units which are not part of electric rate base using the weighted average long-term debt cost of capital. These carrying costs will be amortized over ten years beginning in approximately 2020.

Pipeline integrity management costs represent costs incurred to comply with regulatory requirements related to natural gas pipelines. PSNC Energy will recover costs totaling $20.3 million over a five-year period beginning November 2016, and remaining costs of $11.3 million have been deferred pending future approval of rate recovery. SCE&G began amortizing $1.9 million of such costs annually in November 2015.

Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by SCE&G or PSNC Energy, and are expected to be recovered over periods of up to approximately 18 years.

Deferred storm damage costs represent costs incurred in excess of amounts previously collected through SCE&G’s SCPSC-approved storm damage reserve, and for which SCE&G expects to receive future recovery through customer rates.

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

Various other regulatory assets are expected to be recovered through rates over varying periods through 2047.

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

The SCPSC, the NCUC or the FERC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other regulatory assets include, but are not limited to, certain costs which have not been specifically approved for recovery by the SCPSC, the NCUC or by the FERC. In recording such costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders. The costs are currently not being recovered, but are expected to be recovered through rates in future periods. In the future, as a result of deregulation or other changes in the regulatory environment or changes in accounting requirements, the Company or Consolidated SCE&G could be required to write off all or a portion of 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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3.COMMON EQUITY

SCANA had 200 million shares of common stock authorized as of March 31, 2017 and December 31, 2016. Gains and losses on cash flow hedges reclassified from AOCI during the three months ended March 31, 2017 resulted in higher interest expense of $2 million and lower cost of gas purchased for resale of $2 million. Such reclassifications during the comparable period in 2016 resulted in higher interest expense of $2 million and higher cost of gas purchased for resale of $5 million.

Authorized shares of SCE&G common stock were 50 million as of March 31, 2017 and December 31, 2016. Authorized shares of SCE&G preferred stock were 20 million, of which 1,000 shares, no par value, were issued and outstanding as of March 31, 2017 and December 31, 2016. All issued and outstanding shares of SCE&G's common and preferred stock are held by SCANA.

4.     LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

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

Liquidity

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

	March 31, 2017
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)	869.5		50.4			769.9			49.2
Weighted average interest rate			1.47		%	1.22		%	1.27		%
Letters of credit supported by LOC	3.3		3.0			0.3			—
Available	$	1,127.2	$	346.6		$	629.8		$	150.8

	December 31, 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)	940.5		64.4			804.3			71.8
Weighted average interest rate			1.43		%	1.04		%	1.07		%
Letters of credit supported by LOC	3.3		3.0			0.3			—
Available	$	1,056.2	$	332.6		$	595.4		$	128.2

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. Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $28 million at March 31, 2017, and $29 million at December 31, 2016. On its balance sheet, Consolidated SCE&G includes such amounts within Affiliated payables.

5. INCOME TAXES

The Company files consolidated federal income tax returns which include Consolidated SCE&G, and the Company and its subsidiaries file various applicable state and local income tax returns.

The IRS has completed examinations of the Company’s federal returns through 2004, and the Company’s federal returns through 2007 are closed for additional assessment. The IRS is currently examining SCANA's open federal returns through 2015 as a result of claims discussed below. With few exceptions, the Company, including Consolidated SCE&G, is no longer subject to state and local income tax examinations by tax authorities for years before 2010.

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

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

These income tax deductions and credits are considered to be uncertain tax positions, and under relevant accounting guidance, estimates of the amounts of related tax benefits which may not be sustained upon examination by the taxing authorities are required to be recorded as unrecognized tax benefits in the financial statements. As of March 31, 2017, the Company and Consolidated SCE&G have recorded an unrecognized tax benefit of $382 million ($274 million and $333 million for the Company and Consolidated SCE&G, respectively, net of the impact of state deductions on federal returns, and net of certain operating loss and tax credit carryforwards and, for the Company, receivables related to the uncertain tax positions). If recognized, $17 million of the tax benefit would affect the Company’s and Consolidated SCE&G's effective tax rate (see discussion below regarding deferral of benefits related to 2015 forward). It is reasonably possible that these unrecognized tax benefits may increase by an additional $273 million within the next 12 months as additional expenditures giving rise to pilot model tax benefits are incurred. It is also reasonably possible that these unrecognized tax benefits may decrease by $53 million within the next 12 months if the claims on the amended returns which are currently in appeals are resolved and that resolution were also applied to the 2013 and 2014 returns. No other material changes in the status of the Company’s or Consolidated SCE&G's tax positions have occurred through March 31, 2017.

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 and 2017’s taxable income, the Company and Consolidated SCE&G have recorded regulatory assets for estimated foregone domestic production activities deductions, offset by estimated tax credits, and expect that such (net) deferred costs, along with any interest (see below) and other related deferred costs, will be recoverable through customer rates in future years. SCE&G's current customer rates reflect the availability of domestic production activities deductions (see Note 2).

Estimated interest expense accrued with respect to the unrecognized tax benefits related to the research and experimentation deductions in the 2015 income tax returns has been deferred as a regulatory asset and is expected to be recoverable through customer rates in future years. See also Note 2. Otherwise, the Company and Consolidated SCE&G recognize interest accrued related to unrecognized tax benefits within interest expense or interest income and recognize tax

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penalties within other expenses.  Amounts recorded for such interest income, interest expense or tax penalties have not been material for any periods presented.

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

6. DERIVATIVE FINANCIAL INSTRUMENTS

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

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

Commodity Derivatives

The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types.  Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations. Instruments designated as fair value hedges are used to mitigate exposure to fluctuating market prices created by fixed prices of stored natural gas.  The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy companies and financial institutions.  Cash settlements of commodity derivatives are classified as operating activities in the 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, SCANA Energy, as part of its energy management services, offers fixed price supply contracts which are accounted for as derivatives.  These sales contracts are offset by the purchase of supply futures and swaps which are also accounted for as derivatives. Neither the sales contracts nor the related supply futures and swaps are designated as hedges for accounting purposes.

Interest Rate Swaps

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

Forward starting swap agreements that are designated as cash flow hedges may be used in anticipation of the issuance of debt.  Except as described in the following paragraph, the effective portions of changes in fair value and payments made or

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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 amortized to interest expense or may be applied as otherwise directed by the SCPSC.

Cash payments made or received upon termination of these financial instruments are classified as investing activities for cash flow statement purposes.

Quantitative Disclosures Related to Derivatives

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

	Commodity and Other Energy Management Contracts (in MMBTU)
Hedge designation	Gas Distribution	Gas Marketing	Total
As of March 31, 2017
Commodity contracts	6,500,000	10,134,000	16,634,000
Energy management contracts (a)	—	55,028,797	55,028,797
Total (a)	6,500,000	65,162,797	71,662,797
As of December 31, 2016
Commodity contracts	4,510,000	11,947,000	16,457,000
Energy management contracts (a)	—	67,447,223	67,447,223
Total (a)	4,510,000	79,394,223	83,904,223

(a)  Includes amounts related to basis swap contracts totaling 9,630,864 MMBTU in 2017 and 730,721 MMBTU in 2016.

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

Interest Rate Swaps
	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2017		December 31, 2016		March 31, 2017		December 31, 2016
Designated as hedging instruments	$	115.6	$	115.6	$	36.4	$	36.4
Not designated as hedging instruments	1,285.0		1,285.0		1,285.0		1,285.0

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 March 31, 2017
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments	—		$	2	—		$	1
	Other deferred credits and other liabilities	—		25		—		8
Commodity contracts
	Prepayments	$	1	—		—		—
	Other current assets	1		—		—		—
Total		$	2	$	27	—		$	9
Not designated as hedging instruments
Interest rate contracts
	Other deferred debits and other assets	$	77	—		$	77	—
	Derivative financial instruments	—		$	22	—		$	22
	Other deferred credits and other liabilities	—		3		—		3
Commodity contracts
	Prepayments	2		—		—		—
Energy management contracts
	Prepayments	2		1		—		—
	Other current assets	2		—		—		—
	Other deferred debits and other assets	1		—		—		—
	Derivative financial instruments	—		3		—		—
	Other deferred credits and other liabilities	—		1		—		—
Total		$	84	$	30	$	77	$	25
As of December 31, 2016
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments	—		$	4	—		$	1
	Other deferred credits and other liabilities	—		24		—		8
Commodity contracts
	Prepayments	$	5	—		—		—
	Other current assets	1		—		—		—
Total		$	6	$	28	—		$	9
Not designated as hedging instruments
Interest rate contracts
	Other deferred debits and other assets	$	71	—		$	71	—
	Derivative financial instruments	—		$	27	—		$	27
	Other deferred credits and other liabilities	—		3		—		3
Commodity contracts
	Other current assets	3		—		—		—
Energy management contracts
	Prepayments	6		2		—		—
	Other current assets	2		1		—		—
	Other deferred debits and other assets	2		—		—		—
	Derivative financial instruments	—		4		—		—
	Other deferred credits and other liabilities	—		2		—		—
Total		$	84	$	39	$	71	$	30

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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
Millions of dollars	2017	2016			Location	2017			2016
Three Months Ended March 31,
Interest rate contracts	—	$	(3	)	Interest expense	$	(1	)	$	(1	)

The Company:
	Loss Recognized in OCI, net of tax							Gain/(Loss) Reclassified from AOCI into Income, net of tax
Millions of dollars	2017			2016			Location	2017			2016
Three Months Ended March 31,
Interest rate contracts	—			$	(3	)	Interest expense	$	(2	)	$	(2	)
Commodity contracts	$	(2	)	(2		)	Gas purchased for resale	2			(5		)
Total	$	(2	)	$	(5	)		$	—		$	(7	)

As of March 31, 2017, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $0.6 million as a decrease to gas cost, assuming natural gas markets remain at their current levels, and approximately $6.5 million as an increase to interest expense.  As of March 31, 2017, all of the Company’s commodity cash flow hedges settle by their terms before the end of the second quarter of 2019.

As of March 31, 2017, 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 $1.7 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:
	Gain (Loss) Deferred in Regulatory Accounts						Loss Reclassified from Deferred Accounts into Income
Millions of dollars	2017		2016			Location	2017			2016
Three Months Ended March 31,
Interest rate contracts	$	11	$	(144	)	Interest Expense	$	(1	)	—

As of March 31, 2017, 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 $2.4 million as an increase to interest expense.

Credit Risk Considerations

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

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Derivative Contracts with Credit Contingent Features
	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2017		December 31, 2016		March 31, 2017		December 31, 2016
in Net Liability Position
Aggregate fair value of derivatives in net liability position	$	46.0	$	50.3	$	26.4	$	30.3
Fair value of collateral already posted	30.4		29.2		9.0		9.2
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	$	15.6	$	21.1	$	17.4	$	21.1
in Net Asset Position
Aggregate fair value of derivatives in net asset position	$	69.9	$	62.9	$	69.6	$	62.0
Fair value of collateral already posted	—		—		—		—
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	$	69.9	$	62.9	$	69.6	$	62.0

In addition, for fixed price supply contracts offered to certain of SCANA Energy's customers, the Company could have called on letters of credit in the amount of $1.8 million related to $6.0 million in commodity derivatives that are in a net asset position at March 31, 2017, compared to letters of credit in the amount of $1.5 million related to derivatives of $9.0 million at December 31, 2016, 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 March 31, 2017
Gross Amounts of Recognized Assets	$	77		$	4	$	5		$	86		$	77
Gross Amounts Offset in Statement of Financial Position	—			—		(1		)	(1		)	—
Net Amounts Presented in Statement of Financial Position	77			4		4			85			77
Gross Amounts Not Offset - Financial Instruments	(8		)	—		—			(8		)	(8		)
Gross Amounts Not Offset - Cash Collateral Received	—			—		—			—			—
Net Amount	$	69		$	4	$	4		$	77		$	69
Balance sheet location
Prepayments									$	4		—
Other current assets									2			—
Other deferred debits and other assets									79			$	77
Total									$	85		$	77
As of December 31, 2016
Gross Amounts of Recognized Assets	$	71		$	9	$	10		$	90		$	71
Gross Amounts Offset in Statement of Financial Position	—			—		(4		)	(4		)	—
Net Amounts Presented in Statement of Financial Position	71			9		6			86			71
Gross Amounts Not Offset - Financial Instruments	(9		)	—		—			(9		)	(9		)
Gross Amounts Not Offset - Cash Collateral Received	—			—		—			—			—
Net Amount	$	62		$	9	$	6		$	77		$	62
Balance sheet location
Prepayments									$	9		—
Other current assets									5			—
Other deferred debits and other assets									72			$	71
Total									$	86		$	71

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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 March 31, 2017
Gross Amounts of Recognized Liabilities	$	52		—	$	5		$	57		$	34
Gross Amounts Offset in Statement of Financial Position	—			—	(1		)	(1		)	—
Net Amounts Presented in Statement of Financial Position	52			—	4			56			34
Gross Amounts Not Offset - Financial Instruments	(8		)	—	—			(8		)	(8		)
Gross Amounts Not Offset - Cash Collateral Posted	(29		)	—	(1		)	(30		)	(9		)
Net Amount	$	15		—	$	3		$	18		$	17
Balance sheet location
Derivative financial instruments								$	27		$	23
Other deferred credits and other liabilities								29			11
Total								$	56		$	34
As of December 31, 2016
Gross Amounts of Recognized Liabilities	$	58		—	$	9		$	67		$	39
Gross Amounts Offset in Statement of Financial Position	—			—	(3		)	(3		)	—
Net Amounts Presented in Statement of Financial Position	58			—	6			64			39
Gross Amounts Not Offset - Financial Instruments	(9		)	—	—			(9		)	(9		)
Gross Amounts Not Offset - Cash Collateral Posted	(29		)	—	—			(29		)	(9		)
Net Amount	$	20		—	$	6		$	26		$	21
Balance sheet location
Derivative financial instruments								$	35		$	28
Other deferred credits and other liabilities								29			11
Total								$	64		$	39

7. FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

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

	As of March 31, 2017						As of December 31, 2016
	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	$	15	—		—		$	14	—		—
Held to maturity securities	—		$	7	—		—		$	7	—
Interest rate contracts	—		77		$	77	—		71		$	71
Commodity contracts	3		1		—		8		1		—
Energy management contracts	2		3		—		6		4		—
Liabilities:
Interest rate contracts	—		52		34		—		58		39
Energy management contracts	—		8		—		2		10		—

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

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value measurements for either period presented, and there were no transfers of fair value amounts into or out of Levels 1, 2 or 3 during the periods presented.

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

Long-Term Debt	March 31, 2017				December 31, 2016
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
The Company	$	6,482.7	$	7,029.0	$	6,489.8	$	7,183.3
Consolidated SCE&G	5,158.7		5,606.6		5,166.0		5,752.3

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
	2017			2016			2017		2016
Three months ended March 31,
Service cost	$	5.3		$	5.5		$	1.2	$	1.3
Interest cost	9.4			9.9			2.9		3.0
Expected return on assets	(13.8		)	(14.1		)	—		—
Prior service cost amortization	0.4			1.0			—		0.1
Amortization of actuarial losses	3.9			3.7			0.4		0.1
Net periodic benefit cost	$	5.2		$	6.0		$	4.5	$	4.5

Consolidated SCE&G	Pension Benefits						Other Postretirement Benefits
	2017			2016			2017		2016
Three months ended March 31,
Service cost	$	4.4		$	4.5		$	1.0	$	1.0
Interest cost	8.1			8.4			2.4		2.5
Expected return on assets	(11.8		)	(11.9		)	—		—
Prior service cost amortization	0.3			0.8			—		0.1
Amortization of actuarial losses	3.4			3.1			0.3		0.1
Net periodic benefit cost	$	4.4		$	4.9		$	3.7	$	3.7

No significant contribution to the pension trust is expected for the foreseeable future based on current market conditions and assumptions, 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 Unit 1) maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear

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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 $450 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 liable for up to $127.3 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $18.9 million of the liability per reactor would be assessed per year. SCE&G’s maximum assessment, based on its two-thirds ownership of Unit 1, would be $84.8 million per incident, but not more than $12.6 million per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years.

SCE&G currently maintains insurance policies (for itself and on behalf of Santee Cooper) with NEIL. The policies provide coverage to Unit 1 for property damage and outage costs up to $2.75 billion resulting from an event of nuclear origin and up to $2.33 billion resulting from an event of a non-nuclear origin. In addition, a builder's risk insurance policy has been purchased from NEIL for the construction of the New Units. This policy provides the owners of the New Units up to $500 million of total coverage for accidental property damage occurring during construction. The NEIL policies, in the aggregate, are subject to a maximum loss of $2.75 billion for any single loss occurrence. All of the NEIL policies permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $45.8 million. SCE&G currently maintains an excess property insurance policy (for itself and on behalf of Santee Cooper) with EMANI. The policy provides coverage to Unit 1 for property damage and outage costs up to $415 million resulting from an event of a non-nuclear origin. The EMANI policy permits retrospective assessments under certain conditions to cover insurer's losses. Based on the current annual premium, SCE&G's portion of the retrospective premium assessment would not exceed $1.8 million.

To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from an incident at Unit 1 exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G's rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G has no reason to anticipate a serious nuclear or other incident.  However, if such an incident were to occur, it likely would have a material impact on the Company’s and Consolidated SCE&G's results of operations, cash flows and financial position.

New Nuclear Construction

SCE&G, on behalf of itself and as agent for Santee Cooper, entered into the EPC Contract with the Consortium in 2008 for the design and construction of the New Units. SCE&G's ownership share in the New Units is 55%. As discussed below, various difficulties have been encountered in connection with the project. The ability of the construction team to adhere to established budgets and construction schedules has been affected by many variables, including unanticipated difficulties encountered in connection with project engineering and the construction of project components, constrained financial resources of the contractors, regulatory, legal, training and construction processes associated with securing approvals, permits and licenses and necessary amendments to them within projected timeframes, the availability of labor and materials at estimated costs, the efficiency of project labor and weather. There have also been contractor and supplier performance issues, difficulties in timely meeting critical regulatory requirements, contract disputes, and changes in key contractors or subcontractors. No assurance can be given that these and other construction-related difficulties will not continue to be experienced as construction progresses.

EPC Contract and BLRA Matters

The construction of the New Units and SCE&G’s related recovery of financing costs through rates is subject to review and approval by the SCPSC as provided for in the BLRA. Under the BLRA, the SCPSC has approved, among other things, a milestone schedule and a capital costs estimates schedule for the New Units. This approval constitutes a final and binding determination that the New Units are used and useful for utility purposes, and that the capital costs associated with the New Units are prudent utility costs and expenses and are properly included in rates, so long as the New Units are constructed or are being constructed within the parameters of the approved milestone schedule, including specified contingencies, and the approved capital costs estimates schedule. Subject to the same conditions, the BLRA provides that SCE&G may apply to the SCPSC annually for an order to recover through revised rates SCE&G’s weighted average cost of capital applied to all or part of the outstanding balance of construction work in progress concerning the New Units. Estimated operating costs, including the depreciation of the utility plant costs, are to be recovered through rates beginning when the construction of each New Unit is completed and it is placed into service. As of March 31, 2017, SCE&G’s investment in the New Units, including related transmission, totaled $4.6 billion, for which the financing costs on $3.8 billion have been reflected in rates under the BLRA.

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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, and again in September 2015 and November 2016 (see discussion below), the SCPSC approved SCE&G's requested updates to the milestone schedule, revised contractual substantial completion dates, and increases in capital and other costs. It is anticipated that further approval by the SCPSC is likely to be required as a consequence of the Consortium’s bankruptcy proceedings, as further described below.

October 2015 Amendment and WEC's Engagement of Fluor

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

Among other things, the October 2015 Amendment provided SCE&G and Santee Cooper an option to fix the total amount to be paid to the Consortium for its entire scope of work on the project (excluding a limited amount of work within the time and materials component of the contract price) after June 30, 2015 at $6.082 billion (SCE&G’s 55% portion being approximately $3.345 billion). This total amount to be paid would be reduced by amounts paid since June 30, 2015. SCE&G, on behalf of itself and as agent for Santee Cooper, executed the fixed price option, subject to SCPSC approval, on July 1, 2016.

The October 2015 Amendment:

(i) resolved by settlement and release most outstanding disputes between SCE&G and the Consortium,

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

(iii) revised the delay-related liquidated damages computation requirements, including those related to the eligibility of the New Units to earn IRC Section 45J production tax credits (see also below), resulting in escalating liquidated damages that are capped at an aggregate of $338 million per New Unit (SCE&G’s 55% portion being approximately $186 million per New Unit),

(iv) provided for payment to the Consortium of a completion bonus of $150 million per New Unit (SCE&G’s 55% portion being approximately $83 million per New Unit) for each New Unit placed in service by the deadline to qualify for production tax credits,

(v) provided for development of a revised construction milestone payment schedule,

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

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

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

November 2016 SCPSC Order

In May 2016, SCE&G petitioned the SCPSC for approval of updated construction and capital cost schedules for the New Units which were developed in connection with the October 2015 Amendment. On November 9, 2016, the SCPSC approved a settlement agreement among SCE&G, ORS and certain other parties concerning this petition. The SCPSC also approved SCE&G's election of the fixed price option.

The construction schedule approved by the SCPSC in November 2016 provided for contractual guaranteed substantial completion dates of August 31, 2019 and August 31, 2020 for Units 2 and 3, respectively. The approved capital cost schedule includes incremental capital costs that total $831 million. Under such approved capital cost schedule, SCE&G’s total project capital cost would be approximately $6.8 billion including owner’s costs and transmission, or $7.7 billion with escalation and AFC. In addition, the SCPSC approved revising SCE&G’s allowed ROE for new nuclear construction from 10.5% to 10.25%. This revised ROE will be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2017. In addition, SCE&G may not file future requests to amend capital cost schedules prior to January 28, 2019, unless its annual revised rate request is denied because SCE&G is out of compliance with its approved capital cost schedule or BLRA construction milestone schedule. In most circumstances, if the projected commercial operation date for Unit

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2 is extended, the expiration of the January 28, 2019 moratorium will be extended by an equal amount of time. Finally, following the expiration of the January 28, 2019 moratorium, SCE&G's right to file future budget increase requests with the SCPSC is limited in certain circumstances to the extent those requests are not associated with change orders, DRB orders, transmission costs, certain time and materials costs, and certain owners’ costs.

On February 28, 2017, the SCPSC issued its order denying the Petitions for Rehearing filed by certain parties that were not included in the settlement. The time period to file a Notice of Appeal of the SCPSC’s decision with the South Carolina Supreme Court has expired for three of the four non-settling parties, and none of those parties has filed a Notice of Appeal.  The remaining non-settling party has until May 8, 2017, to file a Notice of Appeal.

DRB Activity

The October 2015 Amendment established a DRB process for resolving certain commercial claims and disputes. The DRB is comprised of three members chosen by the parties and, under the DRB process, amounts in dispute of less than $5 million are to be resolved by the DRB without recourse. Amounts in dispute greater than $5 million are to be resolved by the DRB for the remainder of the construction of the New Units, with a reserved right to further arbitrate or to litigate such issues at the conclusion of construction.

On February 24, 2017, following SCE&G’s nonpayment of certain invoices upon its assertion that WEC had not fulfilled documentation requirements imposed by the DRB, WEC referred a related claim to the DRB. SCE&G then provided the DRB a response and WEC in turn provided its rebuttal; however, following the Consortium’s bankruptcy filing on March 29, 2017, action regarding this DRB referral ceased.

Payment and Performance Obligations, Contractor Bankruptcy Proceedings and Related Uncertainties

Payment and performance obligations under the EPC Contract are joint and several obligations of WEC and WECTEC, and in connection with the October 2015 Amendment, Toshiba, WEC’s parent company, reaffirmed its guaranty of WEC’s payment obligations. Additionally, the EPC Contract provides the owners the right, exercisable upon certain conditions, to obtain payment and performance bonds from WEC equal to 15%of the highest projected three months' billings during the applicable year, and their aggregate nominal coverage will not 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 obtained annual 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 automatically renew for successive one-year periods until their final expiration date of August 31, 2020, unless the issuer provides a minimum 60-day notice that it will not renew. If the issuer provides notice that it will not renew, SCE&G may draw upon the standby letter of credit prior to its expiration. In the event that WEC were not to meet its payment and performance obligations under the EPC Contract, it is anticipated that this funding would provide a source of liquidity. In addition, the EPC Contract provides that upon the request of SCE&G, and at owners' cost, the Consortium must escrow certain intellectual property and software for the owners' benefit to assist in completion of the New Units. An escrow arrangement has been established, andWEC has reported that substantially all of the required intellectual property and software have been deposited. SCE&G is attempting to verify that this information is present in useable form.

On March 29, 2017, WEC and WECTEC, the two members of the Consortium, and certain of their affiliates filed petitions for protection under Chapter 11 of the U.S. Bankruptcy Code, citing a liquidity crisis arising from project contract losses attributable to the New Units and the Vogtle Units as a material factor that caused them to seek protection under the bankruptcy laws. In connection with the filing, SCE&G, Santee Cooper, WEC and WECTEC entered into the Interim Assessment Agreement which, as amended, expires on June 26, 2017 unless otherwise terminated. Under the terms of the Interim Assessment Agreement and while it remains in effect, all parties have agreed to continue to perform under the EPC Contract and to give SCE&G and Santee Cooper the right to discuss project status with Fluor and other subcontractors and vendors and to obtain relevant project information and documents from them. SCE&G and Santee Cooper are obligated to pay all costs incurred by the Consortium, Fluor, other subcontractors and vendors for work performed or services rendered while the Interim Assessment Agreement remains in effect. SCE&G and Santee Cooper have also agreed not to draw on the letters of credit discussed above so long as the Interim Assessment Agreement is in effect.

In April of 2017, Toshiba, following several announcements and media reports and following WEC’s and WECTEC’s bankruptcy petitions, announced that it had recorded an impairment charge of approximately $6.2 billion relating to its nuclear

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power systems business, leaving it with negative shareholders’ equity. Toshiba also disclosed that, although these conditions and events raise substantial doubt, it believed that its responses to such conditions, including the sale of a portion of its computer memory business as then anticipated by Toshiba, would enable it to continue to operate as a going concern. Additionally, Toshiba indicated that it intends to significantly alter its risk management oversight of its nuclear business, and in its filings with the Bankruptcy Court, the Consortium stated that it intends to discontinue its role in the construction of nuclear plants. However, there can be no assurance that such sales or other actions will be successful. As such, there can be no assurance that Toshiba will fulfill its payment guaranty obligations under the EPC Contract.

In February 2017, WEC notified the Company and Consolidated SCE&G that the contractual guaranteed substantial completion dates of August 2019 and 2020 for Unit 2 and Unit 3, respectively, which were reflected in the October 2015 Amendment, are not likely to be met. Instead, WEC provided further revised estimated substantial completion dates of April 2020 and December 2020. These later dates remain within the SCPSC-approved 18-month contingency periods provided for under the BLRA, and achievement of such dates would also allow the output of both units to qualify, under current law, for federal production tax credits (see below). However, there can be no assurance that these dates will be achieved in light of WEC’s historical inability to achieve forecasted productivity and work force efficiency levels and in light of the Consortium’s bankruptcy filing.

Pursuant to the Interim Assessment Agreement, SCE&G and Santee Cooper are evaluating the various elements of the project, including forecasted costs and completion dates, while construction continues and SCE&G and Santee Cooper continue to make payments for such work. The initial term of the Interim Assessment Agreement was 30 days and it has been amended to extend its term through June 26, 2017; however, it may also be terminated earlier by SCE&G or Santee Cooper. Any decision to further extend the Interim Assessment Agreement may be impacted by the willingness of the other parties thereto. Termination of the Interim Assessment Agreement prior to such time that SCE&G and Santee Cooper have completed a full evaluation may adversely impact the continuation of construction of the project.

If, as a result of the bankruptcy process, the benefit of the fixed-price terms provided by the EPC Contract is lost, and part or all of the cost overruns expected to be incurred by the Consortium become the responsibility of SCE&G and Santee Cooper, these cost increases may or may not be recoverable from the Consortium or from Toshiba under its payment guaranty, or may materially exceed the amount of the Consortium's payment obligations guaranteed by Toshiba, which in general are limited to 25 percent of the payments made to the Consortium at the time of its breach under the EPC Contract. The ability of SCE&G to recover any increased costs through rates will be subject to review and approval by the SCPSC, and such costs may or may not qualify for recovery under the BLRA. For example, certain parties may challenge such costs as not being subject to recovery under the BLRA as a result of the terms of the settlement agreement approved by the SCPSC on November 9, 2016.

If, as part of the bankruptcy process, the EPC Contract is rejected, then SCE&G and Santee Cooper will need to engage replacement contractors and/or assume responsibilities of the contractor under the EPC Contract in order to complete the New Units. Alternatively, SCE&G and Santee Cooper could also decide to abandon the construction of one or both of the New Units, leaving SCE&G to pursue cost recovery under the abandonment provisions of the BLRA.

The Consortium has agreed not to reject the EPC Contract prior to the date of termination of the Interim Assessment Agreement; however, after the end of the term of the Interim Assessment Agreement, it is likely that the EPC Contract will be rejected. If the EPC Contract is rejected during the bankruptcy process, it is unlikely that SCE&G and Santee Cooper will be able to negotiate replacement contracts on similar terms with members of the Consortium, and there can be no assurance that some or all of the members of the Consortium will have roles in connection with the design, engineering or construction of the New Units. Additionally, there can be no assurance that any such replacement contracts will provide protection against future construction cost increases through a negotiated fixed price or that they will not assign some or all of the risks for escalating costs onto the owners. There also can be no assurance that SCE&G and Santee Cooper will be able to complete the construction of the New Units without significant delay or additional costs, should they decide to move forward with the project. Such delays could result in the loss of qualification for production tax credits referred to above and disclosed below.

A number of subcontractors and vendors to the Consortium, including Fluor, have alleged non-payment by the Consortium for amounts owed for work performed on the New Units.  SCE&G is contesting the filed liens.  SCE&G estimates that the aggregate amount of claims for which subcontractor and vendor liens have been filed is approximately $118 million (SCE&G’s 55% portion being approximately $65 million), of which $50 million (SCE&G’s 55% share being $27.5 million) have been paid.  SCE&G will continue to evaluate the issues relating to these claims during the pendency of the bankruptcy proceeding.

Jointly-owned projects, such as the current construction of the New Units, are also subject to risks such as (1) one or more of the joint owners becoming either unable or unwilling to continue to fund project financial commitments, (2) new joint

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owners being sought but not being secured at equivalent financial terms, or (3) disagreement among joint owners or changes in the joint ownership make-up which further increase project costs, further delay the completion of the project or result in the termination of all or a portion of the project.

The Consortium’s bankruptcy filing could have a material impact on the construction of the New Units and could have a material impact on SCANA’s and SCE&G’s results of operations, cash flows and financial condition. The ultimate outcome of these matters cannot be determined at this time.

Santee Cooper Matters

SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper. Under the terms of this agreement, SCE&G will acquire a 1% ownership interest in the New Units at the commercial operation date of Unit 2, an additional 2% ownership interest no later than the first anniversary of such commercial operation date, and the final 2% no later than the second anniversary of such commercial operation date. SCE&G has agreed to pay an amount equal to Santee Cooper's actual cost, including its cost of financing, of the percentage conveyed as of the date of each conveyance. In addition, the agreement provides that Santee Cooper will not transfer any of its remaining interest in the New Units to third parties until the New Units are complete. This transaction is subject to customary closing conditions, including receipt of necessary regulatory approvals. This transaction will not affect the payment obligations between the parties during construction of the New Units, nor is it anticipated that the payments for the additional ownership interest would be reflected in a revised rates filing under the BLRA. SCE&G’s projected cost for the additional 5% interest being acquired from Santee Cooper was approximately $850 million at December 31, 2016, and is being further evaluated.

Nuclear Production Tax Credits

The IRS has notified SCE&G that, subject to a national megawatt capacity limitation, the electricity to be produced by each of the New Units (advanced nuclear units, as defined) would qualify for nuclear production tax credits under Section 45J of the IRC to the extent that such New Unit is operational before January 1, 2021 and other eligibility requirements are met. These nuclear production tax credits (related to SCE&G's 55% share of both New Units) could total as much as approximately $1.4 billion. Such credits would be earned over the first eight years of each New Unit's operations and would be realized by SCE&G over those years or during allowable carry-forward periods. Based on current tax law and the contractual guaranteed substantial completion dates (and the dates of completion forecasted by WEC in February 2017) provided above, both New Units would be operational and would qualify for the nuclear production tax credits; however, any further delays in the schedule or changes in tax law could adversely impact these conclusions. See also the Payment and Performance Obligations, Contractor Bankruptcy Proceedings and Related Uncertainties discussion above. When and to the extent that production tax credits are realized, their benefits are expected to be provided directly to SCE&G's electric customers.

During March 2017, legislation was introduced in both houses of Congress which would eliminate the requirement that the New Units be operational before January 1, 2021 in order for their electricity production to qualify for the nuclear production tax credits; however, there can be no assurance that such legislation will become law.

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 CO₂ 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 its SIP, 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. As a result of an Executive Order on March 28, 2017, the EPA is reconsidering the rule and the

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Court of Appeals agreed to hold the case in abeyance for 60 days. The Company and Consolidated SCE&G expect any costs incurred to comply with such rule to be recoverable through rates.

In July 2011, the EPA issued the CSAPR to reduce emissions of SO₂ and NO_X from power plants in the eastern half of the United States. The CSAPR replaces the CAIR and requires a total of 28 states to reduce annual SO₂ emissions and annual and ozone season NO_X emissions to assist in attaining the ozone and fine particle NAAQS. The rule establishes an emissions cap for SO₂ and NO_X and limits the trading for emission allowances by separating affected states into two groups with no trading between the groups. The State of South Carolina has chosen to remain in the CSAPR program, even though recent court rulings exempted the state. This allows the state to remain compliant with regional haze standards. Air quality control installations that SCE&G and GENCO have already completed have positioned them to comply with the existing allowances set by the CSAPR. Any costs incurred to comply with CSAPR are expected to be recoverable through rates.

In April 2012, the EPA's MATS rule containing new standards for mercury and other specified air pollutants became effective. The MATS rule has been the subject of ongoing litigation even while it remains in effect. Rulings on this litigation are not expected to have an impact on SCE&G or GENCO due to plant retirements, conversions, and enhancements. SCE&G and GENCO are in compliance with the MATS rule and expect to remain in compliance.

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

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 2018 and will cost an additional $10.1 million, which is accrued in Other within Deferred Credits and Other Liabilities on the consolidated balance sheet. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates. At March 31, 2017, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $25.3 million and are included in regulatory assets.

10. SEGMENT OF BUSINESS INFORMATION

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

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The Company
Millions of dollars	External Revenue		Intersegment Revenue			Operating Income		Net Income
Three Months Ended March 31, 2017
Electric Operations	$	577	$	1		$	178	n/a
Gas Distribution	322		—			113		n/a
Gas Marketing	274		24			n/a		$	15
All Other	—		94			—		—
Adjustments/Eliminations	—		(119		)	25		156
Consolidated Total	$	1,173	$	—		$	316	$	171

Three Months Ended March 31, 2016
Electric Operations	$	592	$	1		$	198	n/a
Gas Distribution	299		1			94		n/a
Gas Marketing	281		22			n/a		$	24
All Other	—		98			—		—
Adjustments/Eliminations	—		(122		)	39		152
Consolidated Total	$	1,172	$	—		$	331	$	176

Consolidated SCE&G
Millions of dollars	External Revenue		Operating Income		Earnings Available to Common Shareholder
Three Months Ended March 31, 2017
Electric Operations	$	578	$	178	n/a
Gas Distribution	141		44		n/a
Adjustments/Eliminations	—		—		$	109
Consolidated Total	$	719	$	222	$	109

Three Months Ended March 31, 2016
Electric Operations	$	593	$	198	n/a
Gas Distribution	124		38		n/a
Adjustments/Eliminations	—		—		$	113
Consolidated Total	$	717	$	236	$	113

Segment Assets	The Company				Consolidated SCE&G
	March 31,		December 31,		March 31,		December 31,
Millions of dollars	2017		2016		2017		2016
Electric Operations	$	12,076	$	11,929	$	12,076	$	11,929
Gas Distribution	2,926		2,892		836		825
Gas Marketing	202		230		n/a		n/a
All Other	997		1,124		n/a		n/a
Adjustments/Eliminations	2,257		2,532		3,053		3,337
Consolidated Total	$	18,458	$	18,707	$	15,965	$	16,091

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11.    AFFILIATED TRANSACTIONS

The Company and Consolidated SCE&G:

SCE&G owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and sale of refined coal to reduce emissions. SCE&G accounts for this investment using the equity method.  Consolidated SCE&G’s total purchases from this affiliate were $44.6 million and $52.8 million for the three months ended March 31, 2017 and 2016, respectively. Consolidated SCE&G’s total sales to this affiliate were $44.4 million and $52.5 million for the three months ended March 31, 2017 and 2016, respectively. The net of the total purchases and total sales are recorded in Other expenses on the condensed consolidated statements of income (for the Company) and of comprehensive income (for Consolidated SCE&G). Consolidated SCE&G’s receivable from this affiliate was $13.5 million at March 31, 2017 and $16.0 million at December 31, 2016.  Consolidated SCE&G’s payable to this affiliate was $13.6 million at March 31, 2017 and $16.1 million at December 31, 2016.

Consolidated SCE&G:

SCE&G purchases natural gas and related pipeline capacity from SCANA Energy to serve its retail gas customers and certain electric generation requirements.  Such purchases totaled approximately $23.9 million and $22.4 million for the three months ended March 31, 2017 and 2016, respectively.  SCE&G’s payables to SCANA Energy for such purchases were $8.3 million at March 31, 2017 and $8.8 million at December 31, 2016.

SCANA Services, on behalf of itself and its parent company, provides the following services to Consolidated SCE&G, which are rendered at direct or allocated cost: information systems, telecommunications, customer support, marketing and sales, human resources, corporate compliance, purchasing, financial, risk management, public affairs, legal, investor relations, gas supply and capacity management, strategic planning, general administrative, and retirement benefits. In addition, SCANA Services processes and pays invoices for Consolidated SCE&G and is reimbursed. Costs for these services, including amounts capitalized, totaled $72.5 million and $75.6 million for the three months ended March 31, 2017 and 2016, respectively. Amounts expensed are recorded in Other operation and maintenance - nonconsolidated affiliate and Other expenses on the condensed consolidated statements of comprehensive income. Consolidated SCE&G's payables to SCANA Services for these services were $45.8 million at March 31, 2017 and $63.5 million at December 31, 2016.

Consolidated SCE&G's money pool borrowings from an affiliate are described in Note 4. SCE&G's participation in SCANA's noncontributory defined benefit pension plan and unfunded postretirement health care and life insurance programs is described in Note 8.

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

OF OPERATIONS

Pursuant to General Instruction H of Form 10-Q, SCE&G is permitted to omit certain information related to itself and its consolidated affiliates called for by Item 2 of Part I of Form 10-Q, and instead provide a management’s narrative analysis of its consolidated results of operation and other information described therein. Such information is presented hereunder specifically for Consolidated SCE&G, but may be presented alongside information presented for the Company generally. Consolidated SCE&G makes no representation as to information relating solely to SCANA and its subsidiaries (other than Consolidated SCE&G).

RESULTS OF OPERATIONS

FOR THE THREE MONTHS ENDED MARCH 31, 2017

AS COMPARED TO THE CORRESPONDING PERIOD IN 2016

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 and SCE&G’s Annual Report on Form 10-K for the year ended December 31, 2016.

Earnings

Earnings were as follows:

The Company	2017		2016
Earnings per share	$	1.19	$	1.23
Consolidated SCE&G
Net income (millions of dollars)	$	112.3	$	116.2

Earnings per share decreased primarily due to lower electric margin, higher depreciation expense, higher property taxes, higher interest cost and lower gas marketing net income, partially offset by higher gas distribution margin, lower other operation and maintenance expenses, higher other income and lower other expenses, as further discussed below.

Consolidated SCE&G's net income decreased primarily due to lower electric margin, higher depreciation expense, higher property taxes and higher interest cost, partially offset by higher gas distribution margin, higher other income and lower other expenses, as further described below.

Dividends Declared

SCANA's Board of Directors declared the following dividends on common stock during 2017:

Declaration Date	Payment Date	Record Date	Dividend Per Share
February 16, 2017	April 1, 2017	March 10, 2017	$0.6125
April 27, 2017	July 1, 2017	June 12, 2017	$0.6125

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

Electric Operations

Electric Operations for the Company and for Consolidated SCE&G 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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	The Company				Consolidated SCE&G
Millions of dollars	2017		2016		2017		2016
Operating revenues	$	578.5	$	592.7	$	578.5	$	592.7
Fuel used in electric generation	136.4		136.2		136.4		136.2
Purchased power	11.1		11.2		11.1		11.2
Margin	431.0		445.3		431.0		445.3
Other operation and maintenance	124.9		125.0		128.5		128.4
Depreciation and amortization	73.0		70.5		70.0		67.7
Other taxes	54.7		52.1		54.1		51.5
Operating Income	$	178.4	$	197.7	$	178.4	$	197.7

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. First quarter weather in SCE&G’s electric service territory was milder than normal in both 2017 and 2016; however, 2017 was milder than 2016.

• Margin decreased due to the effects of weather of $38.9 million and lower residential and commercial average use of $7.5 million. These margin decreases were partially offset by base rate increases under the BLRA of $16.0 million, residential and commercial customer growth of $5.6 million, higher industrial margin of $3.8 million and higher collections under the rate rider for pension costs of $4.0 million. The higher pension rider collections had no impact on net income as they were fully offset by the recognition, within other operation and maintenance expenses, of higher pension costs.

• Other operation and maintenance expenses changed slightly. Labor costs were lower by $1.8 million, primarily due to lower incentive compensation costs partially offset by the recognition of higher pension costs, and non-labor electric generation costs were higher by $1.4 million.

• 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:

Classification	2017	2016
Residential	1,636	1,926
Commercial	1,635	1,724
Industrial	1,459	1,503
Other	134	140
Total Retail Sales	4,864	5,293
Wholesale	213	223
Total Sales	5,077	5,516

Retail sales volumes decreased primarily due to the effects of weather partially offset by customer growth. Wholesale sales volumes decreased due to the effects of weather.

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Gas Distribution

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

	The Company				Consolidated SCE&G
Millions of dollars	2017		2016		2017		2016
Operating revenues	$	322.1	$	299.9	$	140.9	$	124.6
Gas purchased for resale	134.8		132.7		65.9		55.6
Margin	187.3		167.2		75.0		69.0
Other operation and maintenance	42.4		43.1		17.3		17.8
Depreciation and amortization	20.8		19.8		7.0		6.6
Other taxes	10.9		10.5		7.2		6.7
Operating Income (Loss)	$	113.2	$	93.8	$	43.5	$	37.9

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 and SCE&G's Form 10-K for December 31, 2016. The WNA and the CUT affect margins but not sales volumes.

• Margin increased primarily due to an NCUC-approved rate increase effective November 2016 at PSNC Energy of $12.3 million, an SCPSC-approved increase in base rates under the RSA effective November 2016 at SCE&G of $2.1 million and customer growth of $2.7 million at SCE&G and $2.2 million at PSNC Energy.

• Other operation and maintenance expenses decreased primarily due to lower labor costs of $3.6 million at the Company, including $1.2 million at SCE&G, primarily due to lower incentive compensation costs.

• 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 MMBTU) related to gas distribution margin by class, including transportation, were as follows:

	The Company		Consolidated SCE&G
Classification (in thousands)	2017	2016	2017	2016
Residential	16,560	21,095	4,905	6,664
Commercial	9,469	11,090	3,752	4,391
Industrial	5,322	5,058	4,654	4,216
Transportation	10,954	10,818	1,556	1,170
Total	42,305	48,061	14,867	16,441

Residential and commercial firm sales volumes decreased primarily due to the effects of weather partially offset by customer growth. Industrial sales volumes increased primarily due to fewer curtailments in 2017. Transportation volumes increased primarily due to higher natural gas fired electric generation at PSNC Energy and customers shifting from system supply to transportation only service at SCE&G.

Gas Marketing

Gas Marketing is comprised of the Company's nonregulated marketing operation, SCANA Energy, which operates in the southeast and includes Georgia’s retail natural gas market.  Gas Marketing operating revenues and net income were as follows:

Millions of dollars	2017		2016
Operating revenues	$	298.0	$	303.4
Net income	15.1		24.3

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

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Other Operating Expenses

Other operating expenses were as follows:

	The Company				Consolidated SCE&G
Millions of dollars	2017		2016		2017		2016
Other operation and maintenance	$	179.2	$	180.5	$	145.8	$	146.2
Depreciation and amortization	94.4		90.9		77.0		74.3
Other taxes	65.9		63.1		61.3		58.2

Changes in other operating expenses are primarily attributable to the electric operations and gas distribution segments and are addressed in their respective operating income discussions.

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. Each of the Company and 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:

	The Company						Consolidated SCE&G
Millions of dollars	2017			2016			2017			2016
Other income	$	17.0		$	15.8		$	7.7		$	5.6
Other expense	(9.7		)	(13.8		)	(5.5		)	(7.7		)
AFC - equity funds	9.1			5.7			8.6			4.7

Other income at the Company and at Consolidated SCE&G increased $1.6 million due to SCPSC-approved carrying cost recovery on certain deferred items. Other income and other expense at the Company decreased due to lower billings to DCGT for transition services provided at cost pursuant to the terms of the sale of CGT. AFC increased due to construction activity.

Interest Expense

     Interest charges increased primarily due to increased borrowings.

Income Taxes

At the Company and Consolidated SCE&G income tax expense decreased from 2016 to 2017 primarily due to lower income before income taxes. 

LIQUIDITY AND CAPITAL RESOURCES

The Company anticipates that its cash obligations will be met through internally-generated funds and additional short- and long-term borrowings. The Company expects that, barring a future impairment of the capital markets, it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future, including the cash requirements for nuclear construction and refinancing maturing long-term debt. The Company’s ratio of earnings to fixed charges for the three and 12 months ended March 31, 2017 was 3.60 and 3.31, respectively. Consolidated SCE&G’s ratio of earnings to fixed charges for the three and 12 months ended March 31, 2017 was 3.17 and 3.58, 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.

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At March 31, 2017, the Company had net available liquidity of approximately $1.1 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 increased primarily due to receipt of income tax refunds in 2017.

Cash flows from investing activities in 2017 were primarily related to capital expenditures. In 2016, similar levels of capital expenditures were made in addition to funding of collateral deposit requirements with respect to interest rate swaps as interest rates moved.

Cash flows from financing activities in 2017 included normal dividend payments and reductions in commercial paper balances. In 2016, financing activities included normal dividend payments and increases in commercial paper balances.

OTHER MATTERS

For information related to environmental matters, nuclear generation, and claims and litigation, see Note 9 of the condensed consolidated financial statements. For information related to the Company's and Consolidated SCE&G's unrecognized tax benefits, see Note 5 of the condensed consolidated financial statements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

SCANA:

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

For further discussion of changes in long-term debt and interest rate derivatives, including changes in the Company's market risk exposures relative to interest rate risk, see the Liquidity and Capital Resources section in Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations and Notes 2, 4, 6 and 7 of the 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, which are limited to financial positions of SCANA Energy and PSNC Energy, 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.

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Expected Maturity	2017	2018	2019
Futures - Long
Settlement Price (a)	3.22	3.19	3.08
Contract Amount (b)	42.0	18.8	0.9
Fair Value (b)	43.4	19.1	0.9
Futures - Short
Settlement Price (a)	3.41	3.28
Contract Amount (b)	20.7	8.0
Fair Value (b)	20.2	8.0
Options - Purchased Call (Long)
Strike Price (a)	2.42	2.17
Contract Amount (b)	13.5	10.7
Fair Value (b)	1.0	0.8
Swaps - Commodity
Pay fixed/receive variable (b)	14.2	13.8	1.2
Average pay rate (a)	3.3853	3.3494	2.9931
Average received rate (a)	3.3493	3.2393	3.0645
Fair value (b)	14.0	13.4	1.3
Pay variable/receive fixed (b)	18.5	12.7	1.6
Average pay rate (a)	3.3240	3.0982	3.0998
Average received rate (a)	3.2232	3.3082	2.9830
Fair value (b)	18.0	13.6	1.5
Swaps - Basis
Pay variable/receive variable (b)	23.0	8.5	0.3
Average pay rate (a)	3.2609	3.4217	3.1486
Average received rate (a)	3.2367	3.3956	3.0586
Fair value (b)	22.8	8.4	0.3
(a) Weighted average, in dollars
(b) Millions of dollars

ITEM 4. CONTROLS AND PROCEDURES

As of March 31, 2017, 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 March 31, 2017, these disclosure controls and procedures were effective. There has been no change in internal control over financial reporting during the quarter ended March 31, 2017 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 1. LEGAL PROCEEDINGS

On March 29, 2017, WEC and WECTEC, the two members of the Consortium, and certain of their affiliates filed petitions for protection under Chapter 11 of the U.S. Bankruptcy Code with the Bankruptcy Court, citing a liquidity crisis arising from project contract losses attributable to the New Units and the Vogtle Units as a material factor that caused them to seek protection under the bankruptcy laws. For additional information, see the New Nuclear Construction section of Note 9 to the condensed consolidated financial statements under the subheading Payment and Performance Obligations, Contractor Bankruptcy Proceedings and Related Uncertainties.

ITEM 1A. RISK FACTORS

The risk factors from the Registrants' combined Annual Report on Form 10-K for the year ended December 31, 2016, have been updated and are restated below in their entirety.

The risk factors that follow relate in each case to the Company, and where indicated the risk factors also relate to Consolidated SCE&G.

The costs of large capital projects, such as the Company’s and Consolidated SCE&G’s construction for electric generation and environmental compliance are significant, and these projects are subject to a number of risks and uncertainties that may adversely affect the cost, timing and completion of these projects, many of which have been experienced during the construction of the New Units.

The Company’s and Consolidated SCE&G’s businesses are capital intensive and require significant investments in electric generation and in other internal infrastructure projects, including projects for environmental compliance. Achieving the intended benefits of any large construction project is subject to many uncertainties. For instance, the ability to adhere to established budgets and construction schedules may be affected by many variables, such as the regulatory, legal, training and construction processes associated with securing approvals, permits and licenses and necessary amendments to them within projected timeframes, the availability of labor and materials at estimated costs, the availability and cost of financing, and weather. There also may be contractor or supplier performance issues or adverse changes in their creditworthiness and/or financial stability, unforeseen difficulties meeting critical regulatory requirements, contract disputes and litigation, and changes in key contractors or subcontractors. There may be unforeseen engineering problems or unanticipated changes in project design or scope. Our ability to complete construction projects (including new baseload generation) as well as our ability to maintain current operations at reasonable cost could be affected by the availability of key components or commodities, increases in the price of or the unavailability of labor, commodities or other materials, increases in lead times for components, adverse changes in applicable laws and regulations, new or enhanced environmental or regulatory requirements, supply chain failures (whether resulting from the foregoing or other factors), and disruptions in the transportation of components, commodities and fuels. To the extent that in connection with the construction of a project delays occur, costs become unrecoverable, or we otherwise become unable to effectively manage and complete the project, our results of operations, cash flows and financial condition, as well as our qualifications for applicable governmental programs, benefits and tax credits may be adversely affected.

SCE&G and Santee Cooper have agreed to jointly own, contract the design and construction of, and operate the New Units at Summer Station, in pursuit of which they have committed and are continuing to commit significant resources. In addition, construction of significant new transmission infrastructure is necessary to support the New Units and is under way as an integral part of the project. Various difficulties have been encountered in connection with the project. The ability of the construction team to adhere to established budgets and construction schedules has been affected by many variables, including unanticipated difficulties encountered in connection with project engineering and the construction of project components, constrained financial resources of the contractors, regulatory, legal, training and construction processes associated with securing approvals, permits and licenses and necessary amendments to them within projected timeframes, the availability of labor and materials at estimated costs, the efficiency of project labor and weather. There have also been contractor and supplier performance issues, difficulties in timely meeting critical regulatory requirements, contract disputes, and changes in key contractors or subcontractors. No assurance can be given that these and other construction-related difficulties will not continue to be experienced as construction progresses. Jointly-owned projects, such as the current construction of the New Units, are also subject to risks such as (1) one or more of the joint owners becoming either unable or unwilling to continue to fund project financial commitments, (2) new joint owners being sought but not being secured at equivalent financial terms, or (3) disagreement among joint owners or changes in the joint ownership make-up which further increase project costs, further delay the completion of the project or result in the termination of all or a portion of the project.

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The recent bankruptcy filing of members of the Consortium has created heightened risks and substantial uncertainties with respect to the cost, timing, construction and/or completion of the New Units.

On March 29, 2017, WEC and WECTEC, the two members of the Consortium, and certain of their affiliates, filed petitions for protection under Chapter 11 of the United States Bankruptcy Code. The Consortium are presently the primary contractors for the construction and engineering of and procurement for the New Units and the Vogtle Units. The contracts for the New Units and the Vogtle Units provide for the construction of the New Units and the Vogtle Units by the Consortium on a fixed-cost basis (with certain exceptions) and for damages to be payable by the Consortium in the event the projects are not substantially completed by required dates. In documents filed in the Bankruptcy Court, the Consortium cited a liquidity crisis arising from project contract losses attributable to the New Units and the Vogtle Units as a material factor that caused it to seek protection under the bankruptcy laws.

Toshiba, the ultimate parent company of the Consortium and a guarantor of the Consortium’s payment obligations under the EPC Contract, following several announcements and media reports, announced in April of 2017 that it had recorded an impairment charge of approximately $6.2 billion relating to its nuclear power systems business, leaving Toshiba with a negative shareholders’ equity. Toshiba also disclosed that, although these conditions and events raise substantial doubt, it believed that its responses to such conditions, including the sale of a portion of its computer memory business as then anticipated by Toshiba, would enable it to continue to operate as a going concern. Additionally, Toshiba indicated that it intends to significantly alter its risk management oversight of its nuclear business, and in its filings with the Bankruptcy Court, the Consortium stated that it intends to discontinue its role in the construction of nuclear plants. However, there can be no assurance that such sales or other actions will be successful. As such, there can be no assurance that Toshiba will fulfill its payment guaranty obligations under the EPC Contract.

Pursuant to the Interim Assessment Agreement entered into by SCE&G, Santee Cooper, WEC and WECTEC in anticipation of the bankruptcy filing, SCE&G and Santee Cooper are evaluating the various elements of the project, including forecasted costs and completion dates, construction is continuing and SCE&G and Santee Cooper are continuing to make progress payments while work continues. The Interim Assessment Agreement had an initial term of 30 days and has been amended to extend its term through June 26, 2017, but it may also be terminated earlier by SCE&G or Santee Cooper. Any decision to extend the Interim Assessment Agreement may be impacted by the willingness of the other parties thereto. Termination of the Interim Assessment Agreement prior to such time that SCE&G and Santee Cooper have completed a full evaluation may adversely impact the continuation of construction of the project.

If as a result of the bankruptcy process we lose the benefit of the current fixed-price terms provided for by the EPC Contract, part or all of the cost overruns expected to be incurred by the Consortium will become the responsibility of SCE&G and Santee Cooper. These cost increases may or may not be recoverable from the Consortium or from Toshiba under its payment guaranty, or may materially exceed the amount of the Consortium's payment obligations guaranteed by Toshiba, which in general are limited to 25 percent of the payments made to the Consortium at the time of its breach under the EPC Contract. The ability of SCE&G to recover any increased costs through rates will be subject to review and approval by the SCPSC, and such costs may or may not qualify for recovery under the BLRA. If as part of the bankruptcy process the EPC Contract is rejected, then SCE&G and Santee Cooper will need to engage replacement contractors and/or assume the responsibilities of the contractor under the EPC Contract in order to complete the New Units. SCE&G and Santee Cooper could also decide to abandon the construction of one or both of the New Units.

The Consortium has agreed not to reject the EPC Contract prior to the date of termination of the Interim Assessment Agreement; however, after the end of the term of the Interim Assessment Agreement, it is likely that the EPC Contract will be rejected. If the EPC Contract is rejected during the bankruptcy process, it is unlikely that SCE&G and Santee Cooper will be able to negotiate replacement contracts on similar terms with some or all of the members of the Consortium, and there can be no assurance that some or all of the members of the Consortium will have roles in connection with the design, engineering or construction of the New Units. Additionally, there can be no assurance that any such replacement contracts will provide protection against future construction cost increases through a negotiated fixed price or that they will not assign some or all of the risks for escalating costs onto the owners. There also can be no assurance that SCE&G and Santee Cooper will be able to complete the construction of the New Units without significant delay or additional costs, should SCE&G and Santee Cooper decide to move forward with the project. Such delays could result in the loss of qualification for production tax credits. Further, while the BLRA also provides that, in the event of abandonment prior to plant completion, construction work in progress costs incurred, including AFC, and a return on those costs may be recoverable through rates, so long as SCE&G demonstrates by a preponderance of the evidence that its decision to abandon the New Unit(s) was prudent, there can be no assurance that any such costs would be recoverable through rates.

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The Consortium’s bankruptcy filing could have a material impact on the construction of the New Units and could have a material impact on SCANA's and SCE&G’s results of operations, cash flows and financial condition. The ultimate outcome of these matters cannot be determined at this time. A discussion of certain of these matters can be found under New Nuclear Construction in Note 9 to the condensed consolidated financial statements and other risk factors below.

A downgrade in the credit rating of SCANA or any of SCANA’s subsidiaries, including SCE&G, could negatively affect our ability to access capital and to operate our businesses, thereby adversely affecting results of operations, cash flows and financial condition.

Various rating agencies currently rate SCANA’s long-term senior unsecured debt, SCE&G’s long-term senior secured debt, and the long-term senior unsecured debt of PSNC Energy as investment grade. In addition, rating agencies maintain ratings on the short-term debt of SCANA, SCE&G, Fuel Company (which ratings are based upon the guarantee of SCE&G) and PSNC Energy. Rating agencies consider qualitative and quantitative factors when assessing SCANA and its rated operating companies’ credit ratings, including regulatory environment, capital structure and the ability to meet liquidity requirements. Changes in the regulatory environment or deterioration of our rated companies’ commonly monitored financial credit metrics and additional adverse developments with respect to the construction of the New Units could negatively affect their debt ratings. While SCANA and SCE&G’s credit ratings are currently considered investment grade, during the first quarter of 2017, the agencies placed such ratings on negative outlook or watch status due to adverse developments relating to the construction of the New Units. If these rating agencies were to further lower any of these ratings, particularly to below investment grade for long-term debt instruments, borrowing costs on new issuances would increase, which could adversely impact financial results or limit or eliminate refinancing opportunities, and the potential pool of investors and funding sources could decrease.

Commodity price changes, delays in delivery of commodities, commodity availability and other factors may affect the operating cost, capital expenditures and competitive positions of the Company’s and Consolidated SCE&G’s energy businesses, thereby adversely impacting results of operations, cash flows and financial condition.

Our energy businesses are sensitive to changes in coal, natural gas, uranium and other commodity prices (as well as their transportation costs), availability and deliverability. Any such changes could affect the prices these businesses charge, their operating costs, and the competitive position of their products and services. Consolidated SCE&G is permitted to recover the prudently incurred cost of purchased power and fuel (including transportation) used in electric generation through retail customers’ bills, but purchased power and fuel cost increases affect electric prices and therefore the competitive position of electricity against other energy sources. In addition, when natural gas prices are low enough relative to coal to result in the dispatch of gas-fired electric generation ahead of coal-fired electric generation, higher inventories of coal, with related increased carrying costs, may result. This may adversely affect our results of operations, cash flows and financial condition.

In the case of regulated natural gas operations, costs prudently incurred for purchased gas and pipeline capacity may be recovered through retail customers’ bills. However, in both our regulated and deregulated natural gas markets, increases in gas costs affect total retail prices and therefore the competitive position of gas relative to electricity and other forms of energy. Accordingly, customers able to do so may switch to alternate forms of energy and reduce their usage of gas from the Company and Consolidated SCE&G. Customers on a volumetric rate structure unable to switch to alternate fuels or suppliers may reduce their usage of gas from the Company and Consolidated SCE&G. A regulatory mechanism applies to residential and commercial customers at PSNC Energy to mitigate the earnings impact of an increase or decrease in gas usage.

Certain construction-related commodities, such as copper and aluminum used in our transmission and distribution lines and in our electrical equipment, and steel, concrete and rare earth elements, have experienced significant price fluctuations due to changes in worldwide demand. To operate our air emissions control equipment, we use significant quantities of ammonia, limestone and lime. With EPA-mandated industry-wide compliance requirements for air emissions controls, increased demand for these reagents, combined with the increased demand for low sulfur coal, may result in higher costs for coal and reagents used for compliance purposes.

The use of derivative instruments could result in financial losses and liquidity constraints. The Company and Consolidated SCE&G do not fully hedge against financial market risks or price changes in commodities. This could result in increased costs, thereby resulting in lower margins and adversely affecting results of operations, cash flows and financial condition.

The Company and Consolidated SCE&G use derivative instruments, including futures, forwards, options and swaps, to manage our financial market risks. The Company also uses such derivative instruments to manage certain commodity (i.e., natural gas) market risk. We could be required to provide cash collateral or recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities and financial contracts or if a counterparty fails to perform under a contract.

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The Company strives to manage commodity price exposure by establishing risk limits and utilizing various financial instruments (exchange traded and over-the-counter instruments) to hedge physical obligations and reduce price volatility. We do not hedge the entire exposure of our operations from commodity price volatility. To the extent we do not hedge against commodity price volatility or our hedges are not effective, results of operations, cash flows and financial condition may be adversely impacted.

Changing and complex laws and regulations to which the Company and Consolidated SCE&G are subject could adversely affect revenues, increase costs, or curtail activities, thereby adversely impacting results of operations, cash flows and financial condition.

The Company and Consolidated SCE&G operate under the regulatory authority of the United States government and its various regulatory agencies, including the FERC, NRC, SEC, IRS, EPA, the Department of Homeland Security, CFTC and PHMSA. In addition, the Company and Consolidated SCE&G are subject to regulation by the state governments of South Carolina, North Carolina and Georgia via regulatory agencies, state environmental agencies, and state employment commissions. Accordingly, the Company and Consolidated SCE&G must comply with extensive federal, state and local laws and regulations. Such governmental oversight and regulation broadly and materially affect the operation of our businesses. In addition to many other aspects of our businesses, these requirements impact the services mandated or offered to our customers, and the licensing, siting, construction and operation of facilities. They affect our management of safety, the reliability of our electric and natural gas systems, the physical and cyber security of key assets, customer conservation through DSM Programs, information security, the issuance of securities and borrowing of money, financial reporting, interactions among affiliates, the payment of dividends and employment programs and practices. Changes to governmental regulations are continual and potentially costly to effect compliance. Non-compliance with these requirements by third parties, such as our contractors, vendors and agents, may subject the Company and Consolidated SCE&G to operational risks and to liability. We cannot predict the future course of changes in this regulatory environment or the ultimate effect that this changing regulatory environment will have on the Company’s or Consolidated SCE&G’s businesses. Non-compliance with these laws and regulations could result in fines, litigation, loss of licenses or permits, mandated capital expenditures and other adverse business outcomes, as well as reputational damage, which could adversely affect the cash flows, results of operations, and financial condition of the Company and Consolidated SCE&G.

Furthermore, changes in or uncertainty in monetary, fiscal, economic, trade, or regulatory policies of the Federal government may adversely affect the debt and equity markets and the economic climate for the nation, region or particular industries, such as ours or those of our customers. The Company and Consolidated SCE&G could be adversely impacted by changes in tax policy, such as the loss of production tax credits related to the construction of the New Units.

The Company and Consolidated SCE&G are subject to extensive rate regulation which could adversely affect operations. Large capital projects (including the construction of the New Units as previously described), results of DSM Programs, results of DER programs, and/or increases in operating costs may lead to requests for regulatory relief, such as rate increases, which may be denied, in whole or part, by rate regulators. Rate increases may also result in reductions in customer usage of electricity or gas, legislative action and lawsuits. Additionally, in 2017, legislation which would amend the current BLRA was proposed in the S.C. House of Representatives.  In the event this bill were to become law, as proposed, its provisions would not adversely impact SCE&G’s rate recovery with respect to the New Units.  However, there can be no assurance that other legislation which might curtail the BLRA in a manner which would adversely impact SCE&G’s rate recovery with respect to the New Units will not be proposed and passed.

SCE&G’s electric operations in South Carolina and the Company’s gas distribution operations in South Carolina and North Carolina are regulated by state utilities commissions. In addition, the ability of SCE&G to recover the cost of construction of the New Units by SCE&G is subject to rate regulation by the SCPSC. Consolidated SCE&G’s generating facilities are subject to extensive regulation and oversight from the NRC and SCPSC. SCE&G's electric transmission system is subject to extensive regulations and oversight from the SCPSC, NERC and FERC. Implementing and maintaining compliance with the NERC's mandatory reliability standards, enforced by FERC, for bulk electric systems could result in higher operating costs and capital expenditures. Non-compliance with these standards could subject SCE&G to substantial monetary penalties. Our gas marketing operations in Georgia are subject to state regulatory oversight and, for a portion of its operations, to rate regulation. There can be no assurance that Georgia’s gas delivery regulatory framework will remain unchanged as market conditions evolve.

Furthermore, Dodd-Frank affects the use and reporting of derivative instruments. The regulations under this legislation provide for substantial additional regulation of over-the-counter and security-based derivative instruments, among other things, and require numerous rule-makings by the CFTC and the SEC to implement, many of which are still pending final action by

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those federal agencies. The Company and Consolidated SCE&G have determined that they meet the end-user exception to mandatory clearing of swaps under Dodd-Frank. In addition, the Company and Consolidated SCE&G have taken steps to ensure that they are not the party required to report these transactions in real-time (the "reporting party") by transacting solely with swap dealers and major swap participants, when possible, as well as entering into reporting party agreements with counterparties who also are not swap dealers or major swap participants, which establishes that those counterparties are obligated to report the transactions in accordance with applicable Dodd-Frank regulations. While these actions minimize the reporting obligations of the Company, they do not eliminate required recordkeeping for any Dodd-Frank regulated transactions. Despite qualifying for the end-user exception to mandatory clearing and ensuring that neither the Company nor Consolidated SCE&G is the reporting party to a transaction required to be reported in real-time, we cannot predict when the final regulations will be issued or what requirements they will impose.

Although we believe that we have constructive relationships with the regulators, our ability to obtain rate treatment that will allow us to maintain reasonable rates of return is dependent upon regulatory determinations, and there can be no assurance that we will be able to implement rate adjustments when sought.

The Company and Consolidated SCE&G are subject to numerous environmental laws and regulations that require significant capital expenditures, can increase our costs of operations and may impact our business plans or expose us to environmental liabilities.

The Company and Consolidated SCE&G are subject to extensive federal, state and local environmental laws and regulations, including those relating to water quality and air emissions (such as reducing NO_X, SO₂, mercury and particulate matter). Some form of regulation is expected at the federal and state levels to impose regulatory requirements specifically directed at reducing GHG emissions from fossil fuel-fired electric generating units. On August 3, 2015, the EPA issued a revised standard for new power plants by re-proposing NSPS under the CAA for emissions of CO₂ from newly constructed fossil fuel-fired units. The final rule requires all new coal-fired power plants to meet a carbon emission rate of 1,400 pounds CO₂ per MWh. No new coal-fired plants could be constructed without partial carbon capture and sequestration capabilities. The Company and Consolidated SCE&G are monitoring the final rule, but do not plan to construct new coal-fired units in the foreseeable future. In addition, on August 3, 2015, the EPA issued its final rule on emission guidelines for states to follow in developing plans to address GHG emissions from existing units. The rule includes state-specific goals for reducing national CO₂ emissions by 32% from 2005 levels by 2030. However, 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. Also, a number of bills have been introduced in Congress that seek to require GHG emissions reductions from fossil fuel-fired electric generation facilities, natural gas facilities and other sectors of the economy, although none has yet been enacted. In April 2012, the EPA issued the finalized MATS for power plants that requires reduced emissions from new and existing coal and oil-fired electric utility steam generating facilities. The EPA's rule for cooling water intake structures to meet the best technology available became effective in October 2014, and the EPA also issued a final rule in December 2014 regarding the handling of coal ash and other combustion by-products produced by power plant operations. Furthermore, the EPA finalized new standards under the CWA governing effluent limitation guidelines for electric generating units in September 2015.

Compliance with these environmental laws and regulations requires us to commit significant resources toward environmental monitoring, installation of pollution control equipment, emissions fees and permitting at our facilities. These expenditures have been significant in the past and are expected to continue or even increase in the future. Changes in compliance requirements or more restrictive interpretations by governmental authorities of existing requirements may impose additional costs on us (such as the clean-up of MGP sites or additional emission allowances) or require us to incur additional expenditures or curtail some of our cost savings activities (such as the recycling of fly ash and other coal combustion products for beneficial use). Compliance with any GHG emission reduction requirements, including any mandated renewable portfolio standards, also may impose significant costs on us, and the resulting price increases to our customers may lower customer consumption. Such costs of compliance with environmental regulations could negatively impact our businesses and our results of operations and financial position, especially if emissions or discharge limits are reduced or more onerous permitting requirements or additional regulatory requirements are imposed.

Renewable and/or alternative electric generation portfolio standards may be enacted at the federal or state level. In June 2014 the State of South Carolina enacted legislation known as Act 236 with the stated goal for each investor-owned utility to supply up to 2% of its 5-year average retail peak demand with renewable electric generation resources by the end of 2020. A utility, at its option, may supply an additional 1% during this period. Such renewable energy may not be readily available in our service territories and could be costly to build, finance, acquire, integrate, and/or operate. Resulting increases in the price of electricity to recover the cost of these types of generation, as approved by regulatory commissions, could result in lower usage of electricity by our customers. In addition, DER generation at customers’ facilities could result in the loss of sales to those customers. Compliance with potential future portfolio standards could significantly impact our capital expenditures and our

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results of operations and financial condition. Utility scale solar development companies are currently working in South Carolina to develop projects in SCE&G's service territory. The integration of those resources at high penetration levels may be challenging.

The compliance costs of these environmental laws and regulations are important considerations in the Company's and Consolidated SCE&G's strategic planning and, as a result, significantly affect the decisions to construct, operate, and retire facilities, including generating facilities. In effecting compliance with MATS, SCE&G has retired three of its oldest and smallest coal-fired units and converted three others such that they may be gas-fired.

The Company and Consolidated SCE&G are vulnerable to interest rate increases, which would increase our borrowing costs, and we may not have access to capital at favorable rates, if at all. Additionally, potential disruptions in the capital and credit markets may further adversely affect the availability and cost of short-term funds for liquidity requirements and our ability to meet long-term commitments; each could in turn adversely affect our results of operations, cash flows and financial condition.

The Company and Consolidated SCE&G rely on the capital markets, particularly for publicly offered debt and equity, as well as the banking and commercial paper markets, to meet our financial commitments and short-term liquidity needs if internal funds are not available from operations. Changes in interest rates affect the cost of borrowing. The Company’s and Consolidated SCE&G’s business plans, which include significant investments in energy generation and other internal infrastructure projects, reflect the expectation that we will have access to the capital markets on satisfactory terms to fund commitments. Moreover, the ability to maintain short-term liquidity by utilizing commercial paper programs is dependent upon maintaining satisfactory short-term debt ratings and the existence of a market for our commercial paper generally.

The Company’s and Consolidated SCE&G’s ability to draw on our respective bank revolving credit facilities is dependent on the ability of the banks that are parties to the facilities to meet their funding commitments and on our ability to timely renew such facilities. Those banks may not be able to meet their funding commitments to the Company or Consolidated SCE&G if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests from us and other borrowers within a short period of time. Longer-term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant financial institutions could adversely affect our access to liquidity needed for our businesses. Any disruption could require the Company and Consolidated SCE&G to take measures to conserve cash until the markets stabilize or until alternative credit arrangements or other funding for our business needs can be arranged. Such measures could include deferring capital expenditures or other discretionary uses of cash. Disruptions in capital and credit markets also could result in higher interest rates on debt securities, limited or no access to the commercial paper market, increased costs associated with commercial paper borrowing or limitations on the maturities of commercial paper that can be sold (if at all), increased costs under bank credit facilities and reduced availability thereof, and increased costs for certain variable interest rate debt securities of the Company and Consolidated SCE&G.

Disruptions in the capital markets and its actual or perceived effects on particular businesses and the greater economy also adversely affect the value of the investments held within SCANA’s pension trust. A significant long-term decline in the value of these investments may require us to make or increase contributions to the trust to meet future funding requirements. In addition, a significant decline in the market value of the investments may adversely impact the Company’s and Consolidated SCE&G’s results of operations, cash flows and financial condition, including its shareholders’ equity.

The Company and Consolidated SCE&G are engaged in activities for which they have claimed, and expect to claim in the future, research and experimentation tax deductions and credits which are the subject of uncertainty and which may be considered controversial by the taxing authorities.  The outcome of those uncertainties could adversely impact cash flows and financial condition.

The Company and Consolidated SCE&G have claimed significant research and experimentation tax deductions and credits related to the ongoing design and construction activities of the New Units. 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.  (See also Uncertain Income Tax Positions within the Critical Accounting Policies and Estimates section of Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 5 to the consolidated financial statements in the Registrants’ Form 10-K for the year ended December 31, 2016.)

These tax claims primarily involve the timing of recognition of tax deductions rather than permanent tax attributes. The permanent attributes (net), as well as most of the interest accruals required to be recorded with respect to them, have been deferred within regulatory assets. As such, these claims have not had, and are not expected to have in the future, significant direct effects on the Company’s and Consolidated SCE&G’s results of operations.  Nonetheless, the claims have contributed

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significantly to the Company’s and Consolidated SCE&G’s cash flows and are expected to continue to do so through the remainder of the New Units’ construction period.  Also, the claims have provided a significant source of capital and have lessened the level of debt and equity financing that the Company and Consolidated SCE&G have needed to raise in the financial markets.  Future claims are expected to provide similar tax benefits.

However, the claims made to date are under examination, and may be considered controversial, by the IRS.  It is expected that the IRS will also examine future claims.  To the extent that the claims are not sustained on examination or through any subsequent appeal, the Company and Consolidated SCE&G will be required to repay any cash received for tax benefit claims which are ultimately disallowed, along with interest on those amounts.  Such amounts could be significant and could adversely affect the Company's and Consolidated SCE&G's cash flows and financial condition.  In certain circumstances, which management considers to be remote, penalties for underpayment of income taxes could also be assessed.  Additionally, in such circumstances, the Company and Consolidated SCE&G may need to access the capital markets to fund those tax and interest payments, which could in turn adversely impact their ability to access financial markets for other purposes.

Operating results may be adversely affected by natural disasters, man-made mishaps and abnormal weather.

The Company has delivered less gas and, in deregulated markets, received lower prices for natural gas when weather conditions have been milder than normal, and as a consequence earned less income from those operations. Mild weather in the future could adversely impact the revenues and results of operations and harm the financial condition of the Company and Consolidated SCE&G. Hot or cold weather could result in higher bills for customers and result in higher write-offs of receivables and in a greater number of disconnections for non-payment. In addition, for the Company and Consolidated SCE&G, severe weather can be destructive, causing outages and property damage, adversely affecting operating expenses and revenues.

Natural disasters (such as hurricanes or other significant weather events, electromagnetic events or the 2011 earthquake and tsunami in Japan) or man-made mishaps (such as the San Bruno, California natural gas transmission pipeline failure, electric utility companies' ash pond failures, and cyber-security failures experienced by many businesses) could have direct significant impacts on the Company and Consolidated SCE&G and on our key contractors and suppliers or could impact us through changes to federal, state or local policies, laws and regulations, and have a significant impact on our financial condition, operating expenses, and cash flows.

Potential competitive changes may adversely affect our gas and electricity businesses due to the loss of customers, reductions in revenues, or write-down of stranded assets.

The utility industry has been undergoing structural change for a number of years, resulting in increasing competitive pressures on electric and natural gas utility companies. Competition in wholesale power sales via an RTO/ISO is in effect across much of the country, but the Southeastern utilities have retained the traditional bundled, vertically integrated structure. Should an RTO/ISO-market be implemented in the Southeast, potential risks emerge from reliance on volatile wholesale market prices as well as increased costs associated with new delivery transmission and distribution infrastructure.

Some states have also mandated or encouraged unbundled retail competition. Should this occur in South Carolina or North Carolina, increased competition may create greater risks to the stability of utility earnings generally and may in the future reduce earnings from retail electric and natural gas sales. In a deregulated environment, formerly regulated utility companies that are not responsive to a competitive energy marketplace may suffer erosion in market share, revenues and profits as competitors gain access to their customers. In addition, the Company’s and Consolidated SCE&G’s generation assets would be exposed to considerable financial risk in a deregulated electric market. If market prices for electric generation do not produce adequate revenue streams and the enabling legislation or regulatory actions do not provide for recovery of the resulting stranded costs, a write-down in the value of the related assets could be required.

The Company and Consolidated SCE&G are subject to the risk of loss of sales due to the growth of distributed generation especially in the form of renewable power such as solar photovoltaic systems, which systems have undergone a rapid decline in their costs. As a result of federal and state subsidies, potential regulations allowing third-party retail sales, and advances in distributed generation technology, the growth of such distributed generation could be significant in the future. Such growth will lessen Company and Consolidated SCE&G sales and will slow growth, potentially causing higher rates to customers.

The Company and SCE&G are subject to risks associated with changes in business and economic climate which could adversely affect revenues, results of operations, cash flows and financial condition and could limit access to capital.

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Sales, sales growth and customer usage patterns are dependent upon the economic climate in the service territories of the Company and SCE&G, which may be affected by regional, national or even international economic factors. Adverse events, economic or otherwise, may also affect the operations of suppliers and key customers. Such events may result in the loss of suppliers or customers, in higher costs charged by suppliers, in changes to customer usage patterns and in the failure of customers to make timely payments to us. With respect to the Company, such events also could adversely impact the results of operations through the recording of a goodwill or other asset impairment. The success of local and state governments in attracting new industry to our service territories is important to our sales and growth in sales, as are stable levels of taxation (including property, income or other taxes) which may be affected by local, state, or federal budget deficits, adverse economic climates generally, legislative actions (including tax reform), or regulatory actions. Budget cutbacks also adversely affect funding levels of federal and state support agencies and non-profit organizations that assist low income customers with bill payments.

In addition, conservation and demand side management efforts and/or technological advances may cause or enable customers to significantly reduce their usage of the Company’s and SCE&G’s products and adversely affect sales, sales growth, and customer usage patterns. For instance, improvements in energy storage technology, if realized, could have dramatic impacts on the viability of and growth in distributed generation.

Factors that generally could affect our ability to access capital include economic conditions and our capital structure. Much of our business is capital intensive, and achievement of our capital plan and long-term growth targets is dependent, at least in part, upon our ability to access capital at rates and on terms that are attractive. If our ability to access capital becomes significantly constrained, our interest costs will likely increase and our financial condition and future results of operations could be adversely impacted.

Problems with operations could cause us to curtail or limit our ability to serve customers or cause us to incur substantial costs, thereby adversely impacting revenues, results of operations, cash flows and financial condition.

Critical processes or systems in the Company’s or Consolidated SCE&G’s operations could become impaired or fail from a variety of causes, such as equipment breakdown, transmission equipment failure, information systems failure or security breach, operator error, natural disasters, and the effects of a pandemic, terrorist attack or cyber attack on our workforce or facilities or on vendors and suppliers necessary to maintain services key to our operations.

In particular, as the operator of power generation facilities, many of which entered service prior to 1985 and may be difficult to maintain, Consolidated SCE&G could incur problems, such as the breakdown or failure of power generation or emission control equipment, transmission equipment, or other equipment or processes which would result in performance below assumed levels of output or efficiency. The operation of the New Units or the integration of a significant amount of distributed generation into our systems may entail additional cycling of our coal-fired generation facilities and may thereby increase the number of unplanned outages at those facilities. In addition, any such breakdown or failure may result in Consolidated SCE&G purchasing emission allowances or replacement power at market rates, if such allowances and replacement power are available at all. These purchases are subject to state regulatory prudency reviews for recovery through rates. If replacement power is not available, such problems could result in interruptions of service (blackout or brownout conditions) in all or part of SCE&G’s territory or elsewhere in the region. Similarly, a natural gas line failure of the Company or Consolidated SCE&G could affect the safety of the public, destroy property, and interrupt our ability to serve customers.

Events such as these could entail substantial repair costs, litigation, fines and penalties, and damage to reputation, each of which could have an adverse effect on the Company’s and Consolidated SCE&G's revenues, results of operations, cash flows, and financial condition. Insurance may not be available or adequate to mitigate the adverse impacts of these events.

A failure of the Company and Consolidated SCE&G to maintain the physical and cyber security of its operations may result in the failure of operations, damage to equipment, or loss of information, and could result in a significant adverse impact to the Company's and Consolidated SCE&G's financial condition, results of operations and cash flows.

The Company and Consolidated SCE&G depend on maintaining the physical and cyber security of their operations and assets.  As much of our business is part of the nation's critical infrastructure, the loss or impairment of the assets associated with that portion of our businesses could have serious adverse impacts on the customers and communities that we serve.  Virtually all of the Company's and Consolidated SCE&G's operations are dependent in some manner upon our cyber systems, which encompass electric and gas operations, nuclear and fossil fuel generating plants, human resource and customer systems and databases, information system networks, and systems containing confidential corporate information.  Cyber systems, such as those of the Company and Consolidated SCE&G, are often targets of malicious cyber attacks.  A successful physical or cyber attack could lead to outages, failure of operations of all or portions of our businesses, damage to key components and

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equipment, and exposure of confidential customer, vendor, shareholder, employee, or corporate information.  The Company and Consolidated SCE&G may not be readily able to recover from such events.  In addition, the failure to secure our operations from such physical and cyber events may cause us reputational damage.  Litigation, penalties and claims from a number of parties, including customers, regulators and shareholders, may ensue.  Insurance may not be adequate to mitigate the adverse impacts of these events.  As a result, the Company's and Consolidated SCE&G's financial condition, results of operations, and cash flows may be adversely affected.

SCANA’s ability to pay dividends and to make payments on SCANA’s debt securities may be limited by covenants in certain financial instruments and by the financial results and condition of its subsidiaries, thereby adversely impacting the valuation of our common stock and our access to capital.

We are a holding company that conducts substantially all of our operations through our subsidiaries. Our assets consist primarily of investments in subsidiaries. Therefore, our ability to meet our obligations for payment of interest and principal on outstanding debt and to pay dividends to shareholders and corporate expenses depends on the earnings, cash flows, financial condition and capital requirements of our subsidiaries, and the ability of our subsidiaries, principally Consolidated SCE&G, PSNC Energy and SCANA Energy, to pay dividends or to repay funds to us. Our ability to pay dividends on our common stock may also be limited by existing or future covenants limiting the right of our subsidiaries to pay dividends on their common stock. Any significant reduction in our payment of dividends in the future may result in a decline in the value of our common stock. Such a decline in value could limit our ability to raise debt and equity capital.

A significant portion of Consolidated SCE&G’s generating capacity is derived from nuclear power, the use of which exposes us to regulatory, environmental and business risks. These risks could increase our costs or otherwise constrain our business, thereby adversely impacting our results of operations, cash flows and financial condition.

In 2016, Unit 1 provided approximately 5.8 million MWh, or 25% of our generation. When giving effect to the completion of construction of the New Units, our generating capacity and the percentage of total generating capacity represented by nuclear sources will increase. Hence, SCE&G is subject to various risks of nuclear generation, which include the following:

• The potential harmful effects on the environment and human health resulting from a release of radioactive materials in connection with the operation of nuclear facilities and the storage, handling and disposal of radioactive materials; 

• Limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with our nuclear operations or those of others in the United States;

• The possibility that new laws and regulations could be enacted that could adversely affect the liability structure that currently exists in the United States;

• Uncertainties with respect to procurement of nuclear fuel and suppliers thereof, fabrication of nuclear fuel and related vendors, and the storage of spent nuclear fuel;

• Uncertainties with respect to contingencies if insurance coverage is inadequate; and

• Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their operating lives.

The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate capital expenditures at nuclear plants such as ours. In today’s environment, there is a heightened risk of terrorist attack on the nation’s nuclear facilities, which has resulted in increased security costs at our nuclear plant. Although we have no reason to anticipate a serious nuclear incident, a major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit, resulting in costly changes to units under construction or in operation and adversely impacting our results of operations, cash flows and financial condition. Furthermore, a major incident at a domestic nuclear facility could result in retrospective premium assessments under our nuclear insurance coverages.

Failure to retain and attract key personnel could adversely affect the Company’s and Consolidated SCE&G’s operations and financial performance.

As with many other utilities, a significant portion of our workforce will be eligible for retirement during the next few years. We must attract, retain and develop executive officers and other professional, technical and craft employees with the skills and experience necessary to successfully manage, operate and grow our businesses. Competition for these employees is

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high, and in some cases we must compete for these employees on a regional or national basis. We may be unable to attract and retain these personnel. In particular, the timely hiring, training, licensing and retention of personnel needed for the operation of the New Units is necessary to maintain the schedule for their operation. Further, the Company’s or Consolidated SCE&G’s ability to construct or maintain generation or other assets including the New Units requires the availability of suitable skilled contractor personnel. We may be unable to obtain appropriate contractor personnel at the times and places needed. Labor disputes with employees or contractors covered by collective bargaining agreements also could adversely affect implementation of our strategic plan and our operational and financial performance. Furthermore, increased medical benefit costs of employees and retirees could adversely affect the results of operations of the Company and Consolidated SCE&G. Medical costs in this country have risen significantly over the past number of years and are expected to continue to increase at unpredictable rates. Such increases, unless satisfactorily managed by the Company and Consolidated SCE&G, could adversely affect results of operations.

The Company and Consolidated SCE&G are subject to the risk that strategic decisions made by us either do not result in a return of or on invested capital or might negatively impact our competitive position, which can adversely impact our results of operations, cash flows, financial condition, and access to capital.

From time to time, the Company and Consolidated SCE&G make strategic decisions that may impact our direction with regard to business opportunities, the services and technologies offered to customers or that are used to serve customers, and the generating plants and other infrastructure that form the basis of much of our business. These strategic decisions may not result in a return of or on our invested capital, and the effects of these strategic decisions may have long-term implications that are not likely to be known to us in the short-term. Changing political climates and public attitudes, including customers' concerns regarding rate increases, such as those periodic rate increases under the BLRA, may adversely affect the ongoing acceptability of strategic decisions that have been made (and, in some cases, previously supported by legislation or approved by regulators), to the detriment of the Company or Consolidated SCE&G (e.g., revision or repeal of the BLRA). Over time, these strategic decisions or changing attitudes toward such decisions, which could be adverse to the Company’s or Consolidated SCE&G’s interests, may have a negative effect on our results of operations, cash flows and financial condition, as well as limit our ability to access capital.

The Company and Consolidated SCE&G are subject to the reputational risks that may result from a failure to adhere to high standards related to compliance with laws and regulations, ethical conduct, operational effectiveness, customer service and the safety of employees, customers and the public. These risks could adversely affect the valuation of our common stock and the Company’s and Consolidated SCE&G’s access to capital.

The Company and Consolidated SCE&G are committed to comply with all laws and regulations, to assure reliability of provided services, to focus on the safety of employees, customers and the public, to ensure environmental compliance, to maintain the physical and cyber security of their operations and assets, to maintain the privacy of information related to our customers and employees, and to maintain effective communications with the public and key stakeholder groups, particularly during emergencies and times of crisis. Traditional news media and social media can very rapidly convey information, whether factual or not, to large numbers of people, including customers, investors, regulators, legislators and other stakeholders, and the failure to effectively manage timely, accurate communication through these channels could adversely impact our reputation. The Company and Consolidated SCE&G also are committed to operational excellence, to quality customer service, and, through our Code of Conduct and Ethics, to maintain high standards of ethical conduct in our business operations. A failure to meet these commitments may subject the Company and Consolidated SCE&G not only to fraud, regulatory action, litigation and financial loss, but also to reputational risk that could adversely affect the valuation of SCANA’s stock, adversely affect the Company’s and Consolidated SCE&G’s access to capital, and result in further regulatory oversight. Insurance may not be available or adequate to respond to these events.

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:

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Issuer Purchases of Equity Securities
	(a)	(b)		(c)	(d)
Period	Total number of shares (or units) purchased	Average price paid per share (or unit)		Total number of shares (or units) purchased as part of publicly announced plans or programs	Maximum number (or approximate dollar value) of shares (or units) that may yet be purchased under the plans or programs
January 1 - 31	5,990	$	71.54	5,990
February 1 - 28	—	—		—
March 1 - 31	—	—		—
Total	5,990			5,990	*

*The preceding 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: May 5, 2017		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). Hyperlink is not required pursuant to Rule 105 of Regulation S-T (Instruction 2).
3.02	X		Articles of Amendment dated April 27, 1995 (Filed as Exhibit 4-A 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 December 30, 2016 (Filed as Exhibit 3.05 to Form 10-K dated December 31, 2016 (File No. 001-08809) 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

March 31, 2017

RATIO OF EARNINGS TO FIXED CHARGES

SCANA:	Three Months Ended March 31, 2017		Twelve Months Ended March 31, 2017			Years ended December 31,
Dollars in Millions						2016			2015		2014			2013			2012
Fixed Charges as defined:
Interest on debt		$92.8		$364.0			$356.8			$327.8		$318.2			$305.9			$301.3
Amortization of debt premium, discount and expense (net)	1.0		4.4			4.5			4.7		9.7			5.3			4.9
Interest component on rentals	0.8		3.4			3.5			3.7		4.1			4.9			4.9
Total Fixed Charges (A)		$94.6		$371.8			$364.8			$336.2		$332.0			$316.1			$311.1
Earnings as defined:
Pretax income from continuing operations		$244.9	$855.0			$865.6			$1,138.4			$786.0			$693.8			$601.6
Total fixed charges above	94.6		371.8			364.8			336.2		332.0			316.1			311.1
Pretax equity in (earnings) losses of investees	0.1		(0.6		)	(0.7		)	0.8		(1.4		)	(3.2		)	(3.3		)
Cash distributions from equity investees	0.9		3.7			3.7			4.0		7.4			9.6			3.3
Total Earnings (B)	$340.5		$1,229.9			$1,233.4			$1,479.4		$1,124.0			$1,016.3			$912.7
Ratio of Earnings to Fixed Charges (B/A)	3.60		3.31			3.38			4.40		3.39			3.22			2.93

SCE&G:	Three Months Ended March 31, 2017		Twelve Months Ended March 31, 2017		Years ended December 31,
Dollars in Millions					2016		2015		2014		2013		2012
Fixed Charges as defined:
Interest on debt		$74.3		$290.7		$284.6		$258.4		$237.6		$226.4		$217.4
Amortization of debt premium, discount and expense (net)	0.7		3.3		3.5		3.7		4.4		4.2		3.9
Interest component on rentals	1.0		4.0		4.0		4.1		4.0		4.5		3.2
Total Fixed Charges (A)		$76.0		$298.0		$292.1		$266.2		$246.0		$235.1		$224.5
Earnings as defined:
Pretax income from continuing operations		$163.8		$765.5		$774.1		$711.0		$676.0		$579.7		$509.5
Total fixed charges above	76.0		298.0		292.1		266.2		246.0		235.1		224.5
Pretax equity in losses of investees	0.8		2.9		3.1		5.0		5.3		3.5		3.8
Total Earnings (B)		$240.6	$1,066.4		$1,069.3			$982.2		$927.3		$818.3		$737.8
Ratio of Earnings to Fixed Charges (B/A)	3.17		3.58		3.66		3.69		3.77		3.48		3.29

EX-31.01

Exhibit 31.01

CERTIFICATION

I, Kevin B. Marsh, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: May 5, 2017
	/s/Kevin B. Marsh
	Kevin B. Marsh
	Chairman of the Board, President, Chief Executive Officer and
	Chief Operating Officer

EX-31.02

Exhibit 31.02

CERTIFICATION

I, Jimmy E. Addison, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: May 5, 2017
	/s/Jimmy E. Addison
	Jimmy E. Addison
	Executive Vice President and Chief Financial Officer

EX-31.03

Exhibit 31.03

CERTIFICATION

I, Kevin B. Marsh, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: May 5, 2017
	/s/Kevin B. Marsh
	Kevin B. Marsh
	Chairman of the Board and Chief Executive Officer

EX-31.04

Exhibit 31.04

CERTIFICATION

I, Jimmy E. Addison, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: May 5, 2017
	/s/Jimmy E. Addison
	Jimmy E. Addison
	Executive Vice President and Chief Financial Officer

EX-32.01

Exhibit 32.01 

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of SCANA Corporation (the “Company”) on Form 10-Q for the quarter ended March 31, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), we certify pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

Date: May 5, 2017
/s/Kevin B. Marsh	/s/Jimmy E. Addison
Kevin B. Marsh	Jimmy E. Addison
Chairman of the Board, President, Chief Executive Officer	Executive Vice President and Chief Financial Officer
and Chief Operating Officer

EX-32.02

Exhibit 32.02

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of South Carolina Electric & Gas Company (the “Company”) on Form 10-Q for the quarter ended March 31, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), we certify pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

Date: May 5, 2017
/s/Kevin B. Marsh	/s/Jimmy E. Addison
Kevin B. Marsh	Jimmy E. Addison
Chairman of the Board and Chief Executive Officer	Executive Vice President and Chief Financial Officer

XML

Document and Entity Information Document	3 Months Ended
	Mar. 31, 2017 shares
Entity Information [Line Items]
Entity Registrant Name	SCANA Corporation
Entity Central Index Key	0000754737
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Mar. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding	142,916,917
SCEG
Entity Information [Line Items]
Entity Registrant Name	SOUTH CAROLINA ELECTRIC & GAS CO
Entity Central Index Key	0000091882
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-Q
Document Period End Date	Mar. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding	40,296,147

XML

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Assets
Utility Plant In Service	$ 13,543	$ 13,444
Accumulated Depreciation and Amortization	(4,494)	(4,446)
Construction Work in Progress	5,011	4,845
Nuclear Fuel, Net of Accumulated Amortization	265	271
Goodwill, Net of Writedown of $230	210	210
Utility Plant, Net	14,535	14,324
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	275	276
Assets held in trust, net-nuclear decommissioning	126	123
Other investments	77	76
Nonutility Property and Investments, Net	478	475
Current Assets:
Cash and cash equivalents	12	208
Receivables, net of allowance for uncollectible accounts	549	616
Other	94	127
Income Taxes receivable	6	142
Inventories (at average cost):
Fuel	114	136
Materials and supplies	153	155
Prepaid Expense	103	105
Other current assets	16	17
Total Current Assets	1,047	1,506
Deferred Debits and Other Assets:
Regulatory Assets, Noncurrent	2,128	2,130
Other	270	272
Total Deferred Debits and Other Assets	2,398	2,402
Total	18,458	18,707
Capitalization and Liabilities
Common Stock, Value, Outstanding	2,389	2,390
Retained Earnings, Unappropriated	3,468	3,384
Accumulated Other Comprehensive Income (Loss), Net of Tax	(51)	(49)
Stockholders' Equity Attributable to Parent	5,806	5,725
Long-term Debt, Excluding Current Maturities	6,466	6,473
Total Capitalization	12,272	12,198
Current Liabilities:
Short-term borrowings	869	941
Current portion of long-term debt	17	17
Accounts payable	269	404
Customer deposits and customer prepayments	158	168
Taxes accrued	59	201
Interest accrued	92	84
Dividends declared	85	80
Derivative financial instruments	27	35
Other	85	135
Total Current Liabilities	1,661	2,065
Deferred Credits and Other Liabilities:
Deferred Income Tax Liabilities, Net	2,184	2,159
Asset retirement obligations	562	558
Pension and other postretirement benefits	375	373
Unrecognized Tax Benefits	274	219
Regulatory Liabilities	938	930
Other	192	205
Total Deferred Credits and Other Liabilities	4,525	4,444
Commitments and Contingencies
Total	18,458	18,707
SCEG
Assets
Utility Plant In Service	11,588	11,510
Accumulated Depreciation and Amortization	(4,032)	(3,991)
Construction Work in Progress	4,950	4,813
Nuclear Fuel, Net of Accumulated Amortization	265	271
Utility Plant, Net	12,771	12,603
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	69	69
Assets held in trust, net-nuclear decommissioning	126	123
Other investments	3	3
Nonutility Property and Investments, Net	198	195
Current Assets:
Cash and cash equivalents	11	164
Receivables, net of allowance for uncollectible accounts	328	378
Other	66	94
Income Taxes receivable	0	53
Due from Affiliate, Current	14	16
Inventories (at average cost):
Fuel	78	83
Materials and supplies	143	143
Prepaid Expense	88	88
Other current assets	2	1
Total Current Assets	730	1,020
Deferred Debits and Other Assets:
Regulatory Assets, Noncurrent	2,026	2,030
Other	240	243
Total Deferred Debits and Other Assets	2,266	2,273
Total	15,965	16,091
Capitalization and Liabilities
Common Stock, Value, Outstanding	2,860	2,860
Retained Earnings, Unappropriated	2,513	2,481
Accumulated Other Comprehensive Income (Loss), Net of Tax	(3)	(3)
Stockholders' Equity Attributable to Parent	5,370	5,338
Stockholders' Equity Attributable to Noncontrolling Interest	135	134
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	5,505	5,472
Long-term Debt, Excluding Current Maturities	5,147	5,154
Total Capitalization	10,652	10,626
Current Liabilities:
Short-term borrowings	770	804
Current portion of long-term debt	12	12
Accounts payable	152	247
Due to Affiliate, Current	100	122
Customer deposits and customer prepayments	114	126
Taxes accrued	102	195
Interest accrued	72	68
Dividends declared	79	79
Derivative financial instruments	23	28
Other	37	55
Total Current Liabilities	1,461	1,736
Deferred Credits and Other Liabilities:
Deferred Income Tax Liabilities, Net	1,951	1,939
Asset retirement obligations	526	522
Pension and other postretirement benefits	234	232
Unrecognized Tax Benefits	333	236
Regulatory Liabilities	705	695
Other	88	89
Other -affiliate	15	16
Total Deferred Credits and Other Liabilities	3,852	3,729
Total	$ 15,965	$ 16,091

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) shares in Millions, $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Common Stock, Shares, Outstanding	142.9	142.9
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	$ 137	$ 138
Public Utilities, Property, Plant and Equipment, Net	14,535	14,324
Allowance for Doubtful Accounts Receivable, Current	6	6
Write-down, Goodwill	230	230
Assets, Current	1,047	1,506
Regulated Entity, Other Assets, Noncurrent	$ 2,398	$ 2,402
SCEG
Common Stock, Shares, Outstanding	40.3	40.3
Public Utilities, Property, Plant and Equipment, Net	$ 12,771	$ 12,603
Allowance for Doubtful Accounts Receivable, Current	3	3
Assets, Current	730	1,020
Regulated Entity, Other Assets, Noncurrent	2,266	2,273
SCEG | Variable Interest Entity, Primary Beneficiary [Member]
Public Utilities, Property, Plant and Equipment, Net	752	756
Assets, Current	74	85
Regulated Entity, Other Assets, Noncurrent	$ 48	$ 52

XML

CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Operating Revenues:
Electric Domestic Regulated Revenue	$ 577	$ 592
Regulated Operating Revenue, Gas	322	299
Gas-nonregulated	274	281
Regulated and Unregulated Operating Revenue	1,173	1,172
Operating Expenses [Abstract]
Fuel used in electric generation	136	136
Purchased power	11	11
Gas purchased for resale	370	359
Other operation and maintenance	179	181
Depreciation and amortization	95	91
Other taxes	66	63
Total Operating Expenses	857	841
Operating Income	316	331
Other Income (Expense):
Other income	17	16
Other expense	(10)	(14)
Interest Expense	(87)	(83)
Allowance for equity funds used during construction	9	5
Total Other Expense	(71)	(76)
Income Before Income Tax Expense	245	255
Income Tax Expense	74	79
Net Income	$ 171	$ 176
Earnings Per Share, Basic and Diluted	$ 1.19	$ 1.23
Per Common Share Data
Weighted Average Number of Shares Outstanding, Basic and Diluted	142.9	142.9
Weighted Average Common Shares Outstanding (millions)
Dividends, Common Stock	$ 87	$ 82
Common Stock, Dividends, Per Share, Declared	$ 0.6125	$ 0.575
SCEG
Operating Revenues:
Electric Domestic Regulated Revenue	$ 577	$ 592
Regulated Operating Revenue, Gas	141	124
Regulated Operating Revenue	719	717
Operating Expenses [Abstract]
Fuel used in electric generation	112	119
Purchased power	11	11
Gas purchased for resale	66	50
Other operation and maintenance	101	96
Depreciation and amortization	77	74
Other taxes	60	56
Total Operating Expenses	497	481
Operating Income	222	236
Other Income (Expense):
Other income	8	5
Other expense	(6)	(8)
Interest Expense	(69)	(66)
Allowance for equity funds used during construction	9	5
Total Other Expense	(58)	(64)
Income Before Income Tax Expense	164	172
Income Tax Expense	52	56
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	112	116
Net Income (Loss) Attributable to Noncontrolling Interest	(3)	(3)
Earnings Available to Common Shareholder	109	113
Weighted Average Common Shares Outstanding (millions)
Dividends, Common Stock	79	74
Affiliated Entity [Member] | SCEG
Operating Revenues:
Electric Domestic Regulated Revenue	1	1
Operating Expenses [Abstract]
Fuel used in electric generation	24	17
Gas purchased for resale	0	6
Other operation and maintenance	45	50
Other taxes	$ 1	$ 2

XML

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Allowance for Funds Used During Construction, Capitalized Interest	$ 6	$ 4
SCEG
Allowance for Funds Used During Construction, Capitalized Interest	$ 6	$ 3

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Net Income (Loss) Attributable to Parent [Abstract]
Net Income (Loss) Available to Common Stockholders, Basic	$ 171	$ 176
Other Comprehensive Income (Loss)
Unrealized gains (losses) on cash flow hedging activities arising during period	(2)	(5)
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	(2)	2
Other Comprehensive Income (Loss)	(2)	2
Comprehensive income available to common shareholder	169	178
SCEG
Other Comprehensive Income (Loss)
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	112	116
Genco
Other Comprehensive Income (Loss)
Less comprehensive income attributable to noncontrolling interest	3	3
SCE&G (including Fuel Company)
Net Income (Loss) Attributable to Parent [Abstract]
Net Income (Loss) Available to Common Stockholders, Basic	109	113
Other Comprehensive Income (Loss)
Comprehensive income available to common shareholder	109	113
Commodity Contract
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(2)	5
Interest Rate Contract
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	2	2
Cash Flow Hedging [Member] | Interest Expense [Member] | Interest Rate Contract
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ (2)	$ (2)

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Tax	$ 0	$ 0
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	(1)	(3)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax	1	1
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income, Tax	$ (1)	$ 3

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Cash Flows From Operating Activities:
Net Income (Loss) Available to Common Stockholders, Basic	$ 171	$ 176
Adjustments to reconcile net income to net cash provided from operating activities:
Deferred Income Tax Expense (Benefit)	27	(11)
Depreciation and amortization	100	94
Amortization of nuclear fuel	14	14
Allowance for equity funds used during construction	(9)	(5)
Carrying cost recovery	(5)	(4)
Cash provided (used) by changes in certain assets and liabilities:
Increase (Decrease) in Receivables	67
Increase (Decrease) Income Taxes Receivable	136
Increase (Decrease) in Inventories	6	11
increase (Decrease) in Prepaid Expense	(5)	(11)
Increase (Decrease) in Other Regulatory Assets	(4)
Increase (Decrease) in Regulatory liabilities	(3)	(1)
Increase (Decrease ) in Accounts payable	(48)	(39)
Unrecognized tax benefits, increase (decrease)	55
Increase (Decrease) in Taxes accrued	(142)	(159)
Increase (Decrease) in Derivative Assets and Liabilities	(3)	(3)
Changes in other assets	(2)	(20)
Changes in other liabilities	(46)	19
Net Cash Provided From Operating Activities	309	61
Cash Flows From Investing Activities:
Property additions and construction expenditures	(342)	(385)
Proceeds from investments (including derivative collateral posted)	19	198
Purchase of investments (including derivative collateral posted)	(20)	(264)
Net Cash Used in Investing Activities	(343)	(451)
Cash Flows From Financing Activities:
Repayments of Long-term Debt	(8)	(8)
Dividends	(82)	(78)
Short-term borrowings, net	(72)	386
Net Cash Provided From Financing Activities	(162)	300
Net (Decrease) Increase in Cash and Cash Equivalents	(196)	(90)
Cash and Cash Equivalents, January 1	208	176
Cash and Cash Equivalents, March 31	12	86
Supplemental Cash Flow Information:
Cash paid for-Interest (net of capitalized interest )	76	77
Cash paid for-Income taxes	0	141
Noncash Investing and Financing Activities:
Accrued construction expenditures	57	142
Capital Lease Obligations Incurred		5
SCEG
Cash Flows From Operating Activities:
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	112	116
Adjustments to reconcile net income to net cash provided from operating activities:
Deferred Income Tax Expense (Benefit)	12	(15)
Depreciation and amortization	79	76
Amortization of nuclear fuel	14	14
Allowance for equity funds used during construction	(9)	(5)
Carrying cost recovery	(5)	(4)
Cash provided (used) by changes in certain assets and liabilities:
Increase (Decrease) in Receivables	45	7
Increase (Decrease) Income Taxes Receivable	53
Increase (Decrease) in Due from Affiliates, Current	2	(2)
Increase (Decrease) in Inventories	(7)	(3)
increase (Decrease) in Prepaid Expense	0	(3)
Increase (Decrease) in Other Regulatory Assets	(2)	2
Increase (Decrease) in Regulatory liabilities	0	(1)
Increase (Decrease ) in Accounts payable	(11)	(23)
Unrecognized tax benefits, increase (decrease)	97	0
Increase (Decrease) in Due to Affiliate, Current	(21)	(8)
Increase (Decrease) in Taxes accrued	(93)	(223)
Changes in other assets	1	(8)
Changes in other liabilities	(14)	25
Net Cash Provided From Operating Activities	253	(55)
Cash Flows From Investing Activities:
Property additions and construction expenditures	(282)	(337)
Proceeds from investments (including derivative collateral posted)	10	171
Purchase of investments (including derivative collateral posted)	(12)	(239)
Investment In Affiliate		9
Net Cash Used in Investing Activities	(284)	(396)
Cash Flows From Financing Activities:
Repayments of Long-term Debt	(8)	(8)
Dividends	(79)	(75)
Short-term borrowings-affiliate,net	(1)	11
Short-term borrowings, net	(34)	450
Net Cash Provided From Financing Activities	(122)	378
Net (Decrease) Increase in Cash and Cash Equivalents	(153)	(73)
Cash and Cash Equivalents, January 1	164	130
Cash and Cash Equivalents, March 31	11	57
Supplemental Cash Flow Information:
Cash paid for-Interest (net of capitalized interest )	61	63
Income Taxes Paid	3	175
Proceeds from Income Tax Refunds	143	7
Noncash Investing and Financing Activities:
Accrued construction expenditures	$ 46	109
Capital Lease Obligations Incurred		$ 5

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Interest Paid, Capitalized	$ 6	$ 4
SCEG
Interest Paid, Capitalized	$ 6	$ 3

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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]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stockholders' Equity before Treasury Stock	$ 2,402
Treasury Stock, Value	(12)
Retained Earnings, Appropriated	3,118			$ 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
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest			$ 5,151
Stockholders' Equity Attributable to Parent	$ 5,443
Common Stock, Value, Outstanding				$ 2,760
Shares, Outstanding	143			40
Common Stock, Dividends, Per Share, Declared	$ 0.575
Net Income (Loss) Available to Common Stockholders, Basic	$ 176			$ 113
Net Income (Loss) Attributable to Noncontrolling Interest			3		3
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest			116
Dividends			74	72
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders					2
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	(5)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax	0
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	2
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	7
Other Comprehensive Income (Loss)	2
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	178			113
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax	0
Dividends, Common Stock	(82)		(74)
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders					2
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	(5)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax	0
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	2
Stockholders' Equity before Treasury Stock	2,402
Treasury Stock, Value	(12)
Retained Earnings, Appropriated	3,212			2,306
AOCI before Tax, Attributable to Parent	(7)	$ (5)
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	(51)
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	(12)
Accumulated Other Comprehensive Income (Loss)	(63)			$ (3)
Stockholders' Equity Attributable to Noncontrolling Interest					130
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest			5,193
Stockholders' Equity Attributable to Parent	$ 5,539
Shares, Outstanding	143			40
AOCI before Tax, Attributable to Parent	$ (7)	(5)
Stockholders' Equity before Treasury Stock	2,402
Treasury Stock, Value	(12)
Retained Earnings, Appropriated	3,384		2,481	$ 2,481
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	(36)
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	(13)
Accumulated Other Comprehensive Income (Loss)	(49)			(3)
Stockholders' Equity Attributable to Noncontrolling Interest			134		134
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest			5,472
Stockholders' Equity Attributable to Parent	5,725		5,338
Common Stock, Value, Outstanding	$ 2,390		2,860	$ 2,860
Shares, Outstanding	143			40
Common Stock, Dividends, Per Share, Declared	$ 0.6125
Net Income (Loss) Available to Common Stockholders, Basic	$ 171			$ 109
Net Income (Loss) Attributable to Noncontrolling Interest			3		3
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest			112
Dividends			79	77
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders					2
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	(2)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax	0
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	(2)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	0
Other Comprehensive Income (Loss)	(2)
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	169			109
Treasury Stock Purchased	(1)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax	0
Dividends, Common Stock	(87)		(79)
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders					2
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	(2)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax	0
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	(2)
Stockholders' Equity before Treasury Stock	2,402
Treasury Stock, Value	(13)
Retained Earnings, Appropriated	3,468		2,513	2,513
AOCI before Tax, Attributable to Parent	0	(2)
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	(38)
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	(13)
Accumulated Other Comprehensive Income (Loss)	(51)			(3)
Stockholders' Equity Attributable to Noncontrolling Interest			135		$ 135
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest			5,505
Stockholders' Equity Attributable to Parent	5,806		5,370
Common Stock, Value, Outstanding	$ 2,389		$ 2,860	$ 2,860
Shares, Outstanding	143			40
AOCI before Tax, Attributable to Parent	$ 0	$ (2)

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

3 Months Ended

Mar. 31, 2017

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 $487 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, the retail natural gas marketing business (including those activities of segments described in Note 10) are presented within Operating Income, and all other activities are presented 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, 29% and 40% of PSNC Energy’s natural gas inventory at March 31, 2017 and December 31, 2016, respectively, with a carrying value of $4.2 million and $9.8 million, respectively.  Under the terms of this agreement, PSNC Energy receives storage asset management feesof which 75% are credited to rate payers. This agreement expired on March 31, 2017, and was replaced with a similar agreement that expires on March 31, 2019.

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.

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 analysis of contracts with customers to which the guidance might be applicable, particularly large customer contracts, has begun. In addition, activities of the FASB's Transition Resource Group for Revenue Recognition are being monitored, particularly as they relate to the required treatment under the standard of contributions in aid of construction, alternative revenue programs and the collectibility of revenue of utilities subject to rate regulation.

In July 2015, the FASB issued accounting guidance intended to simplify the measurement of inventory cost by requiring most inventory to be measured at the lower of cost and net realizable value. The Company and Consolidated SCE&G adopted this guidance in the first quarter of 2017 and the adoption of this guidance did not have any impact on their respective financial statements.

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

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

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

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

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

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

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

In October 2016, the FASB issued accounting guidance related to the tax effects of intra-entity asset transfers of assets other than inventory. An entity will be required to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The Company and Consolidated SCE&G adopted this guidance in the first quarter 2017 and it had no impact on their respective financial statements.

In November 2016, the FASB issued accounting guidance related to the presentation of restricted cash on the statement of cash flows. The guidance is effective for years beginning in 2018, and the Company and Consolidated SCE&G do not anticipate that its adoption will impact their respective financial statements.

In January 2017, the FASB issued accounting guidance to simplify the accounting for goodwill impairment. The guidance removes Step 2 of the goodwill impairment test. The guidance is effective for years beginning in 2020, though early adoption after January 1, 2017 is allowed. The Company and Consolidated SCE&G have not determined when this guidance will be adopted but do not anticipate that its adoption will have a material impact on their respective financial statements.

In March 2017, the FASB issued accounting guidance to change the required presentation of net periodic pension and postretirement benefit cost. Under the new guidance, the net periodic pension and postretirement benefit cost are to be separated into their service cost components and other components. The service cost components are to be presented in the same line item (or items) as other compensation costs arising from services rendered by employees during the period. The other components are to be reported in the income statement separately from the service cost component and outside operating income. Only the service cost component is eligible for capitalization in assets. This guidance is required to be applied on a retrospective basis for the presentation of the service cost component and the other components of net benefit cost and on a prospective basis for the capitalization of only the service cost component of net benefit cost. The Company and Consolidated SCE&G will adopt the guidance when required in the first quarter of 2018 and have not determined what impact it will have on 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 $487 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, the retail natural gas marketing business (including those activities of segments described in Note 10) are presented within Operating Income, and all other activities are presented 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, 29% and 40% of PSNC Energy’s natural gas inventory at March 31, 2017 and December 31, 2016, respectively, with a carrying value of $4.2 million and $9.8 million, respectively.  Under the terms of this agreement, PSNC Energy receives storage asset management feesof which 75% are credited to rate payers. This agreement expired on March 31, 2017, and was replaced with a similar agreement that expires on March 31, 2019.

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.

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 analysis of contracts with customers to which the guidance might be applicable, particularly large customer contracts, has begun. In addition, activities of the FASB's Transition Resource Group for Revenue Recognition are being monitored, particularly as they relate to the required treatment under the standard of contributions in aid of construction, alternative revenue programs and the collectibility of revenue of utilities subject to rate regulation.

In July 2015, the FASB issued accounting guidance intended to simplify the measurement of inventory cost by requiring most inventory to be measured at the lower of cost and net realizable value. The Company and Consolidated SCE&G adopted this guidance in the first quarter of 2017 and the adoption of this guidance did not have any impact on their respective financial statements.

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

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

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

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

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

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

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

In October 2016, the FASB issued accounting guidance related to the tax effects of intra-entity asset transfers of assets other than inventory. An entity will be required to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The Company and Consolidated SCE&G adopted this guidance in the first quarter 2017 and it had no impact on their respective financial statements.

In November 2016, the FASB issued accounting guidance related to the presentation of restricted cash on the statement of cash flows. The guidance is effective for years beginning in 2018, and the Company and Consolidated SCE&G do not anticipate that its adoption will impact their respective financial statements.

In January 2017, the FASB issued accounting guidance to simplify the accounting for goodwill impairment. The guidance removes Step 2 of the goodwill impairment test. The guidance is effective for years beginning in 2020, though early adoption after January 1, 2017 is allowed. The Company and Consolidated SCE&G have not determined when this guidance will be adopted but do not anticipate that its adoption will have a material impact on their respective financial statements.

In March 2017, the FASB issued accounting guidance to change the required presentation of net periodic pension and postretirement benefit cost. Under the new guidance, the net periodic pension and postretirement benefit cost are to be separated into their service cost components and other components. The service cost components are to be presented in the same line item (or items) as other compensation costs arising from services rendered by employees during the period. The other components are to be reported in the income statement separately from the service cost component and outside operating income. Only the service cost component is eligible for capitalization in assets. This guidance is required to be applied on a retrospective basis for the presentation of the service cost component and the other components of net benefit cost and on a prospective basis for the capitalization of only the service cost component of net benefit cost. The Company and Consolidated SCE&G will adopt the guidance when required in the first quarter of 2018 and have not determined what impact it will have on their respective financial statements.

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RATE AND OTHER REGULATORY MATTERS

3 Months Ended

Mar. 31, 2017

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 SCE&G's participation in a DER program and to recover related 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 27, 2017, the SCPSC approved a settlement agreement among SCE&G, ORS and SCEUC, to increase the total fuel cost component of retail electric rates. SCE&G agreed to set its base fuel component in such a manner as to produce a projected under recovery of $61.0 million over a 12-month period beginning with the first billing cycle of May 2017. SCE&G also agreed to recover, over a 12-month period beginning with the first billing cycle of May 2017, projected DER program costs of approximately $16.5 million. Additionally, deferral of carrying cost will be allowed for base fuel component under collected balances, as they occur.

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 months ended March 31, 2017 totaled $4.3 million. During the three months ended March 31, 2016, carrying costs totaled $3.1 million. SCE&G anticipates that when the New Units are placed in service and accelerated tax depreciation is recognized on them, these deferred income tax assets will decline. When these deferred income tax assets are fully offset by related deferred income tax liabilities, the carrying cost accruals will cease, and the regulatory asset will begin to be amortized.

By order dated March 1, 2017, the SCPSC approved SCE&G’s request to decrease its pension costs rider. The change in the pension rider will decrease annual revenue by approximately $11.9 million. The pension rider is designed to allow SCE&G to recover projected pension costs, net of the previously over-collected balance, over a 12-month period, beginning with the first billing cycle in May 2017.

In January 2017, SCE&G requested in its annual DSM Programs filing to recover $37.0 million of costs and net lost revenues associated with DSM programs, along with an incentive to invest in such programs. On April 27, 2017, the SCPSC approved SCE&G's request effective beginning with the first billing cycle in May 2017.

Gas - PSNC Energy

PSNC Energy was authorized to implement a tracker that provides for biannual rate adjustments to recover the revenue requirement associated with integrity management plant investment and associated costs incurred from prevailing federal standards for pipeline integrity and safety that are not otherwise included in current base rates. On February 15, 2017, PSNC Energy filed its first biannual application for an adjustment to its rates under the Integrity Management Tracker, requesting recovery of an annual revenue requirement of $1.9 million. The NCUC approved this request and the revised rates became effective for service rendered on and after March 1, 2017.

Regulatory Assets and Regulatory Liabilities

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

	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2017		December 31, 2016		March 31, 2017		December 31, 2016
Regulatory Assets:
Accumulated deferred income taxes	$	317	$	316	$	309	$	307
AROs and related funding	425		425		402		403
Deferred employee benefit plan costs	336		342		303		309
Deferred losses on interest rate derivatives	614		620		614		620
Unrecovered plant	113		117		113		117
DSM Programs	59		59		59		59
Carrying costs on deferred tax assets related to nuclear construction	37		32		37		32
Pipeline integrity management costs	37		33		6		6
Environmental remediation costs	31		32		25		26
Deferred storm damage costs	20		20		20		20
Deferred costs related to uncertain tax position	17		15		17		15
Other	122		119		121		116
Total Regulatory Assets	$	2,128	$	2,130	$	2,026	$	2,030

Regulatory Liabilities:
Asset removal costs	$	760	$	755	$	533	$	529
Deferred gains on interest rate derivatives	157		151		157		151
Other	21		24		15		15
Total Regulatory Liabilities	$	938	$	930	$	705	$	695

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

AROs and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Unit 1 and conditional AROs related to generation, transmission and distribution properties, including gas pipelines. These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 110 years.

Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under GAAP. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. In 2013 SCE&G began recovering through utility rates approximately $63 million of deferred pension costs for electric operations over approximately 30 years and approximately $14 million of deferred pension costs for gas operations over approximately 14 years. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees, or up to approximately 11 years.

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

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

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. 

Carrying costs on deferred tax assets related to nuclear construction are calculated on accumulated deferred income tax assets associated with the New Units which are not part of electric rate base using the weighted average long-term debt cost of capital. These carrying costs will be amortized over ten years beginning in approximately 2020.

Pipeline integrity management costs represent costs incurred to comply with regulatory requirements related to natural gas pipelines. PSNC Energy will recover costs totaling $20.3 million over a five-year period beginning November 2016, and remaining costs of $11.3 million have been deferred pending future approval of rate recovery. SCE&G began amortizing $1.9 million of such costs annually in November 2015.

Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by SCE&G or PSNC Energy, and are expected to be recovered over periods of up to approximately 18 years.

Deferred storm damage costs represent costs incurred in excess of amounts previously collected through SCE&G’s SCPSC-approved storm damage reserve, and for which SCE&G expects to receive future recovery through customer rates.

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

Various other regulatory assets are expected to be recovered through rates over varying periods through 2047.

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

The SCPSC, the NCUC or the FERC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other regulatory assets include, but are not limited to, certain costs which have not been specifically approved for recovery by the SCPSC, the NCUC or by the FERC. In recording such costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders. The costs are currently not being recovered, but are expected to be recovered through rates in future periods. In the future, as a result of deregulation or other changes in the regulatory environment or changes in accounting requirements, the Company or Consolidated SCE&G could be required to write off all or a portion of 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 SCE&G's participation in a DER program and to recover related 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 27, 2017, the SCPSC approved a settlement agreement among SCE&G, ORS and SCEUC, to increase the total fuel cost component of retail electric rates. SCE&G agreed to set its base fuel component in such a manner as to produce a projected under recovery of $61.0 million over a 12-month period beginning with the first billing cycle of May 2017. SCE&G also agreed to recover, over a 12-month period beginning with the first billing cycle of May 2017, projected DER program costs of approximately $16.5 million. Additionally, deferral of carrying cost will be allowed for base fuel component under collected balances, as they occur.

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 months ended March 31, 2017 totaled $4.3 million. During the three months ended March 31, 2016, carrying costs totaled $3.1 million. SCE&G anticipates that when the New Units are placed in service and accelerated tax depreciation is recognized on them, these deferred income tax assets will decline. When these deferred income tax assets are fully offset by related deferred income tax liabilities, the carrying cost accruals will cease, and the regulatory asset will begin to be amortized.

By order dated March 1, 2017, the SCPSC approved SCE&G’s request to decrease its pension costs rider. The change in the pension rider will decrease annual revenue by approximately $11.9 million. The pension rider is designed to allow SCE&G to recover projected pension costs, net of the previously over-collected balance, over a 12-month period, beginning with the first billing cycle in May 2017.

In January 2017, SCE&G requested in its annual DSM Programs filing to recover $37.0 million of costs and net lost revenues associated with DSM programs, along with an incentive to invest in such programs. On April 27, 2017, the SCPSC approved SCE&G's request effective beginning with the first billing cycle in May 2017.

Gas - PSNC Energy

PSNC Energy was authorized to implement a tracker that provides for biannual rate adjustments to recover the revenue requirement associated with integrity management plant investment and associated costs incurred from prevailing federal standards for pipeline integrity and safety that are not otherwise included in current base rates. On February 15, 2017, PSNC Energy filed its first biannual application for an adjustment to its rates under the Integrity Management Tracker, requesting recovery of an annual revenue requirement of $1.9 million. The NCUC approved this request and the revised rates became effective for service rendered on and after March 1, 2017.

Regulatory Assets and Regulatory Liabilities

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

	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2017		December 31, 2016		March 31, 2017		December 31, 2016
Regulatory Assets:
Accumulated deferred income taxes	$	317	$	316	$	309	$	307
AROs and related funding	425		425		402		403
Deferred employee benefit plan costs	336		342		303		309
Deferred losses on interest rate derivatives	614		620		614		620
Unrecovered plant	113		117		113		117
DSM Programs	59		59		59		59
Carrying costs on deferred tax assets related to nuclear construction	37		32		37		32
Pipeline integrity management costs	37		33		6		6
Environmental remediation costs	31		32		25		26
Deferred storm damage costs	20		20		20		20
Deferred costs related to uncertain tax position	17		15		17		15
Other	122		119		121		116
Total Regulatory Assets	$	2,128	$	2,130	$	2,026	$	2,030

Regulatory Liabilities:
Asset removal costs	$	760	$	755	$	533	$	529
Deferred gains on interest rate derivatives	157		151		157		151
Other	21		24		15		15
Total Regulatory Liabilities	$	938	$	930	$	705	$	695

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

AROs and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Unit 1 and conditional AROs related to generation, transmission and distribution properties, including gas pipelines. These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 110 years.

Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under GAAP. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. In 2013 SCE&G began recovering through utility rates approximately $63 million of deferred pension costs for electric operations over approximately 30 years and approximately $14 million of deferred pension costs for gas operations over approximately 14 years. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees, or up to approximately 11 years.

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

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

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. 

Carrying costs on deferred tax assets related to nuclear construction are calculated on accumulated deferred income tax assets associated with the New Units which are not part of electric rate base using the weighted average long-term debt cost of capital. These carrying costs will be amortized over ten years beginning in approximately 2020.

Pipeline integrity management costs represent costs incurred to comply with regulatory requirements related to natural gas pipelines. PSNC Energy will recover costs totaling $20.3 million over a five-year period beginning November 2016, and remaining costs of $11.3 million have been deferred pending future approval of rate recovery. SCE&G began amortizing $1.9 million of such costs annually in November 2015.

Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by SCE&G or PSNC Energy, and are expected to be recovered over periods of up to approximately 18 years.

Deferred storm damage costs represent costs incurred in excess of amounts previously collected through SCE&G’s SCPSC-approved storm damage reserve, and for which SCE&G expects to receive future recovery through customer rates.

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

Various other regulatory assets are expected to be recovered through rates over varying periods through 2047.

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

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

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COMMON EQUITY

3 Months Ended

Mar. 31, 2017

Common Equity Note [Line Items]

Stockholders' Equity Note Disclosure [Text Block]

SCANA had 200 million shares of common stock authorized as of March 31, 2017 and December 31, 2016. Gains and losses on cash flow hedges reclassified from AOCI during the three months ended March 31, 2017 resulted in higher interest expense of $2 million and lower cost of gas purchased for resale of $2 million. Such reclassifications during the comparable period in 2016 resulted in higher interest expense of $2 million and higher cost of gas purchased for resale of $5 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 March 31, 2017 and December 31, 2016. Authorized shares of SCE&G preferred stock were 20 million, of which 1,000 shares, no par value, were issued and outstanding as of March 31, 2017 and December 31, 2016. All issued and outstanding shares of SCE&G's common and preferred stock are held by SCANA.

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LONG-TERM AND SHORT-TERM DEBT

3 Months Ended

Mar. 31, 2017

Debt Instrument [Line Items]

Long-term Debt [Text Block]

LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

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

Liquidity

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

	March 31, 2017
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)	869.5		50.4			769.9			49.2
Weighted average interest rate			1.47		%	1.22		%	1.27		%
Letters of credit supported by LOC	3.3		3.0			0.3			—
Available	$	1,127.2	$	346.6		$	629.8		$	150.8

	December 31, 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)	940.5		64.4			804.3			71.8
Weighted average interest rate			1.43		%	1.04		%	1.07		%
Letters of credit supported by LOC	3.3		3.0			0.3			—
Available	$	1,056.2	$	332.6		$	595.4		$	128.2

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. Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $28 million at March 31, 2017, and $29 million at December 31, 2016. On its balance sheet, Consolidated SCE&G includes such amounts within Affiliated payables.

SCEG

Debt Instrument [Line Items]

Long-term Debt [Text Block]

LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

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

Liquidity

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

	March 31, 2017
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)	869.5		50.4			769.9			49.2
Weighted average interest rate			1.47		%	1.22		%	1.27		%
Letters of credit supported by LOC	3.3		3.0			0.3			—
Available	$	1,127.2	$	346.6		$	629.8		$	150.8

	December 31, 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)	940.5		64.4			804.3			71.8
Weighted average interest rate			1.43		%	1.04		%	1.07		%
Letters of credit supported by LOC	3.3		3.0			0.3			—
Available	$	1,056.2	$	332.6		$	595.4		$	128.2

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. Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $28 million at March 31, 2017, and $29 million at December 31, 2016. On its balance sheet, Consolidated SCE&G includes such amounts within Affiliated payables.

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INCOME TAXES

3 Months Ended

Mar. 31, 2017

income tax [Line Items]

Income Tax Disclosure [Text Block]

INCOME TAXES

The Company files consolidated federal income tax returns which include Consolidated SCE&G, and the Company and its subsidiaries file various applicable state and local income tax returns.

The IRS has completed examinations of the Company’s federal returns through 2004, and the Company’s federal returns through 2007 are closed for additional assessment. The IRS is currently examining SCANA's open federal returns through 2015 as a result of claims discussed below. With few exceptions, the Company, including Consolidated SCE&G, is no longer subject to state and local income tax examinations by tax authorities for years before 2010.

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

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

These income tax deductions and credits are considered to be uncertain tax positions, and under relevant accounting guidance, estimates of the amounts of related tax benefits which may not be sustained upon examination by the taxing authorities are required to be recorded as unrecognized tax benefits in the financial statements. As of March 31, 2017, the Company and Consolidated SCE&G have recorded an unrecognized tax benefit of $382 million ($274 million and $333 million for the Company and Consolidated SCE&G, respectively, net of the impact of state deductions on federal returns, and net of certain operating loss and tax credit carryforwards and, for the Company, receivables related to the uncertain tax positions). If recognized, $17 million of the tax benefit would affect the Company’s and Consolidated SCE&G's effective tax rate (see discussion below regarding deferral of benefits related to 2015 forward). It is reasonably possible that these unrecognized tax benefits may increase by an additional $273 million within the next 12 months as additional expenditures giving rise to pilot model tax benefits are incurred. It is also reasonably possible that these unrecognized tax benefits may decrease by $53 million within the next 12 months if the claims on the amended returns which are currently in appeals are resolved and that resolution were also applied to the 2013 and 2014 returns. No other material changes in the status of the Company’s or Consolidated SCE&G's tax positions have occurred through March 31, 2017.

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 and 2017’s taxable income, the Company and Consolidated SCE&G have recorded regulatory assets for estimated foregone domestic production activities deductions, offset by estimated tax credits, and expect that such (net) deferred costs, along with any interest (see below) and other related deferred costs, will be recoverable through customer rates in future years. SCE&G's current customer rates reflect the availability of domestic production activities deductions (see Note 2).

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

Effective January 1, 2017, the State of North Carolina reduced its corporate income tax rate from 4% to 3%. 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

The Company files consolidated federal income tax returns which include Consolidated SCE&G, and the Company and its subsidiaries file various applicable state and local income tax returns.

The IRS has completed examinations of the Company’s federal returns through 2004, and the Company’s federal returns through 2007 are closed for additional assessment. The IRS is currently examining SCANA's open federal returns through 2015 as a result of claims discussed below. With few exceptions, the Company, including Consolidated SCE&G, is no longer subject to state and local income tax examinations by tax authorities for years before 2010.

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

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

These income tax deductions and credits are considered to be uncertain tax positions, and under relevant accounting guidance, estimates of the amounts of related tax benefits which may not be sustained upon examination by the taxing authorities are required to be recorded as unrecognized tax benefits in the financial statements. As of March 31, 2017, the Company and Consolidated SCE&G have recorded an unrecognized tax benefit of $382 million ($274 million and $333 million for the Company and Consolidated SCE&G, respectively, net of the impact of state deductions on federal returns, and net of certain operating loss and tax credit carryforwards and, for the Company, receivables related to the uncertain tax positions). If recognized, $17 million of the tax benefit would affect the Company’s and Consolidated SCE&G's effective tax rate (see discussion below regarding deferral of benefits related to 2015 forward). It is reasonably possible that these unrecognized tax benefits may increase by an additional $273 million within the next 12 months as additional expenditures giving rise to pilot model tax benefits are incurred. It is also reasonably possible that these unrecognized tax benefits may decrease by $53 million within the next 12 months if the claims on the amended returns which are currently in appeals are resolved and that resolution were also applied to the 2013 and 2014 returns. No other material changes in the status of the Company’s or Consolidated SCE&G's tax positions have occurred through March 31, 2017.

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 and 2017’s taxable income, the Company and Consolidated SCE&G have recorded regulatory assets for estimated foregone domestic production activities deductions, offset by estimated tax credits, and expect that such (net) deferred costs, along with any interest (see below) and other related deferred costs, will be recoverable through customer rates in future years. SCE&G's current customer rates reflect the availability of domestic production activities deductions (see Note 2).

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

Effective January 1, 2017, the State of North Carolina reduced its corporate income tax rate from 4% to 3%. 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

3 Months Ended

Mar. 31, 2017

Derivative [Line Items]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

6. DERIVATIVE FINANCIAL INSTRUMENTS

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

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

Commodity Derivatives

The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types.  Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations. Instruments designated as fair value hedges are used to mitigate exposure to fluctuating market prices created by fixed prices of stored natural gas.  The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy companies and financial institutions.  Cash settlements of commodity derivatives are classified as operating activities in the 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, SCANA Energy, as part of its energy management services, offers fixed price supply contracts which are accounted for as derivatives.  These sales contracts are offset by the purchase of supply futures and swaps which are also accounted for as derivatives. Neither the sales contracts nor the related supply futures and swaps are designated as hedges for accounting purposes.

Interest Rate Swaps

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

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

Cash payments made or received upon termination of these financial instruments are classified as investing activities for cash flow statement purposes.

Quantitative Disclosures Related to Derivatives

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

	Commodity and Other Energy Management Contracts (in MMBTU)
Hedge designation	Gas Distribution	Gas Marketing	Total
As of March 31, 2017
Commodity contracts	6,500,000	10,134,000	16,634,000
Energy management contracts (a)	—	55,028,797	55,028,797
Total (a)	6,500,000	65,162,797	71,662,797
As of December 31, 2016
Commodity contracts	4,510,000	11,947,000	16,457,000
Energy management contracts (a)	—	67,447,223	67,447,223
Total (a)	4,510,000	79,394,223	83,904,223

(a)  Includes amounts related to basis swap contracts totaling 9,630,864 MMBTU in 2017 and 730,721 MMBTU in 2016.

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

Interest Rate Swaps
	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2017		December 31, 2016		March 31, 2017		December 31, 2016
Designated as hedging instruments	$	115.6	$	115.6	$	36.4	$	36.4
Not designated as hedging instruments	1,285.0		1,285.0		1,285.0		1,285.0

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

Fair Values of Derivative Instruments
		The Company				Consolidated SCE&G
Millions of dollars	Balance Sheet Location	Asset		Liability		Asset		Liability
As of March 31, 2017
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments	—		$	2	—		$	1
	Other deferred credits and other liabilities	—		25		—		8
Commodity contracts
	Prepayments	$	1	—		—		—
	Other current assets	1		—		—		—
Total		$	2	$	27	—		$	9
Not designated as hedging instruments
Interest rate contracts
	Other deferred debits and other assets	$	77	—		$	77	—
	Derivative financial instruments	—		$	22	—		$	22
	Other deferred credits and other liabilities	—		3		—		3
Commodity contracts
	Prepayments	2		—		—		—
Energy management contracts
	Prepayments	2		1		—		—
	Other current assets	2		—		—		—
	Other deferred debits and other assets	1		—		—		—
	Derivative financial instruments	—		3		—		—
	Other deferred credits and other liabilities	—		1		—		—
Total		$	84	$	30	$	77	$	25
As of December 31, 2016
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments	—		$	4	—		$	1
	Other deferred credits and other liabilities	—		24		—		8
Commodity contracts
	Prepayments	$	5	—		—		—
	Other current assets	1		—		—		—
Total		$	6	$	28	—		$	9
Not designated as hedging instruments
Interest rate contracts
	Other deferred debits and other assets	$	71	—		$	71	—
	Derivative financial instruments	—		$	27	—		$	27
	Other deferred credits and other liabilities	—		3		—		3
Commodity contracts
	Other current assets	3		—		—		—
Energy management contracts
	Prepayments	6		2		—		—
	Other current assets	2		1		—		—
	Other deferred debits and other assets	2		—		—		—
	Derivative financial instruments	—		4		—		—
	Other deferred credits and other liabilities	—		2		—		—
Total		$	84	$	39	$	71	$	30

 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
Millions of dollars	2017	2016			Location	2017			2016
Three Months Ended March 31,
Interest rate contracts	—	$	(3	)	Interest expense	$	(1	)	$	(1	)

The Company:
	Loss Recognized in OCI, net of tax							Gain/(Loss) Reclassified from AOCI into Income, net of tax
Millions of dollars	2017			2016			Location	2017			2016
Three Months Ended March 31,
Interest rate contracts	—			$	(3	)	Interest expense	$	(2	)	$	(2	)
Commodity contracts	$	(2	)	(2		)	Gas purchased for resale	2			(5		)
Total	$	(2	)	$	(5	)		$	—		$	(7	)

As of March 31, 2017, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $0.6 million as a decrease to gas cost, assuming natural gas markets remain at their current levels, and approximately $6.5 million as an increase to interest expense.  As of March 31, 2017, all of the Company’s commodity cash flow hedges settle by their terms before the end of the second quarter of 2019.

As of March 31, 2017, 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 $1.7 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:
	Gain (Loss) Deferred in Regulatory Accounts						Loss Reclassified from Deferred Accounts into Income
Millions of dollars	2017		2016			Location	2017			2016
Three Months Ended March 31,
Interest rate contracts	$	11	$	(144	)	Interest Expense	$	(1	)	—

As of March 31, 2017, 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 $2.4 million as an increase to interest expense.

Credit Risk Considerations

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

Derivative Contracts with Credit Contingent Features
	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2017		December 31, 2016		March 31, 2017		December 31, 2016
in Net Liability Position
Aggregate fair value of derivatives in net liability position	$	46.0	$	50.3	$	26.4	$	30.3
Fair value of collateral already posted	30.4		29.2		9.0		9.2
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	$	15.6	$	21.1	$	17.4	$	21.1
in Net Asset Position
Aggregate fair value of derivatives in net asset position	$	69.9	$	62.9	$	69.6	$	62.0
Fair value of collateral already posted	—		—		—		—
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	$	69.9	$	62.9	$	69.6	$	62.0

In addition, for fixed price supply contracts offered to certain of SCANA Energy's customers, the Company could have called on letters of credit in the amount of $1.8 million related to $6.0 million in commodity derivatives that are in a net asset position at March 31, 2017, compared to letters of credit in the amount of $1.5 million related to derivatives of $9.0 million at December 31, 2016, 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 March 31, 2017
Gross Amounts of Recognized Assets	$	77		$	4	$	5		$	86		$	77
Gross Amounts Offset in Statement of Financial Position	—			—		(1		)	(1		)	—
Net Amounts Presented in Statement of Financial Position	77			4		4			85			77
Gross Amounts Not Offset - Financial Instruments	(8		)	—		—			(8		)	(8		)
Gross Amounts Not Offset - Cash Collateral Received	—			—		—			—			—
Net Amount	$	69		$	4	$	4		$	77		$	69
Balance sheet location
Prepayments									$	4		—
Other current assets									2			—
Other deferred debits and other assets									79			$	77
Total									$	85		$	77
As of December 31, 2016
Gross Amounts of Recognized Assets	$	71		$	9	$	10		$	90		$	71
Gross Amounts Offset in Statement of Financial Position	—			—		(4		)	(4		)	—
Net Amounts Presented in Statement of Financial Position	71			9		6			86			71
Gross Amounts Not Offset - Financial Instruments	(9		)	—		—			(9		)	(9		)
Gross Amounts Not Offset - Cash Collateral Received	—			—		—			—			—
Net Amount	$	62		$	9	$	6		$	77		$	62
Balance sheet location
Prepayments									$	9		—
Other current assets									5			—
Other deferred debits and other assets									72			$	71
Total									$	86		$	71

Derivative Liabilities	The Company										Consolidated SCE&G
Millions of dollars	Interest Rate Contracts			Commodity Contracts	Energy Management Contracts			Total			Interest Rate Contracts
As of March 31, 2017
Gross Amounts of Recognized Liabilities	$	52		—	$	5		$	57		$	34
Gross Amounts Offset in Statement of Financial Position	—			—	(1		)	(1		)	—
Net Amounts Presented in Statement of Financial Position	52			—	4			56			34
Gross Amounts Not Offset - Financial Instruments	(8		)	—	—			(8		)	(8		)
Gross Amounts Not Offset - Cash Collateral Posted	(29		)	—	(1		)	(30		)	(9		)
Net Amount	$	15		—	$	3		$	18		$	17
Balance sheet location
Derivative financial instruments								$	27		$	23
Other deferred credits and other liabilities								29			11
Total								$	56		$	34
As of December 31, 2016
Gross Amounts of Recognized Liabilities	$	58		—	$	9		$	67		$	39
Gross Amounts Offset in Statement of Financial Position	—			—	(3		)	(3		)	—
Net Amounts Presented in Statement of Financial Position	58			—	6			64			39
Gross Amounts Not Offset - Financial Instruments	(9		)	—	—			(9		)	(9		)
Gross Amounts Not Offset - Cash Collateral Posted	(29		)	—	—			(29		)	(9		)
Net Amount	$	20		—	$	6		$	26		$	21
Balance sheet location
Derivative financial instruments								$	35		$	28
Other deferred credits and other liabilities								29			11
Total								$	64		$	39

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

Commodity Derivatives

The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types.  Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations. Instruments designated as fair value hedges are used to mitigate exposure to fluctuating market prices created by fixed prices of stored natural gas.  The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy companies and financial institutions.  Cash settlements of commodity derivatives are classified as operating activities in the 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, SCANA Energy, as part of its energy management services, offers fixed price supply contracts which are accounted for as derivatives.  These sales contracts are offset by the purchase of supply futures and swaps which are also accounted for as derivatives. Neither the sales contracts nor the related supply futures and swaps are designated as hedges for accounting purposes.

Interest Rate Swaps

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

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

Cash payments made or received upon termination of these financial instruments are classified as investing activities for cash flow statement purposes.

Quantitative Disclosures Related to Derivatives

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

	Commodity and Other Energy Management Contracts (in MMBTU)
Hedge designation	Gas Distribution	Gas Marketing	Total
As of March 31, 2017
Commodity contracts	6,500,000	10,134,000	16,634,000
Energy management contracts (a)	—	55,028,797	55,028,797
Total (a)	6,500,000	65,162,797	71,662,797
As of December 31, 2016
Commodity contracts	4,510,000	11,947,000	16,457,000
Energy management contracts (a)	—	67,447,223	67,447,223
Total (a)	4,510,000	79,394,223	83,904,223

(a)  Includes amounts related to basis swap contracts totaling 9,630,864 MMBTU in 2017 and 730,721 MMBTU in 2016.

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

Interest Rate Swaps
	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2017		December 31, 2016		March 31, 2017		December 31, 2016
Designated as hedging instruments	$	115.6	$	115.6	$	36.4	$	36.4
Not designated as hedging instruments	1,285.0		1,285.0		1,285.0		1,285.0

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

Fair Values of Derivative Instruments
		The Company				Consolidated SCE&G
Millions of dollars	Balance Sheet Location	Asset		Liability		Asset		Liability
As of March 31, 2017
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments	—		$	2	—		$	1
	Other deferred credits and other liabilities	—		25		—		8
Commodity contracts
	Prepayments	$	1	—		—		—
	Other current assets	1		—		—		—
Total		$	2	$	27	—		$	9
Not designated as hedging instruments
Interest rate contracts
	Other deferred debits and other assets	$	77	—		$	77	—
	Derivative financial instruments	—		$	22	—		$	22
	Other deferred credits and other liabilities	—		3		—		3
Commodity contracts
	Prepayments	2		—		—		—
Energy management contracts
	Prepayments	2		1		—		—
	Other current assets	2		—		—		—
	Other deferred debits and other assets	1		—		—		—
	Derivative financial instruments	—		3		—		—
	Other deferred credits and other liabilities	—		1		—		—
Total		$	84	$	30	$	77	$	25
As of December 31, 2016
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments	—		$	4	—		$	1
	Other deferred credits and other liabilities	—		24		—		8
Commodity contracts
	Prepayments	$	5	—		—		—
	Other current assets	1		—		—		—
Total		$	6	$	28	—		$	9
Not designated as hedging instruments
Interest rate contracts
	Other deferred debits and other assets	$	71	—		$	71	—
	Derivative financial instruments	—		$	27	—		$	27
	Other deferred credits and other liabilities	—		3		—		3
Commodity contracts
	Other current assets	3		—		—		—
Energy management contracts
	Prepayments	6		2		—		—
	Other current assets	2		1		—		—
	Other deferred debits and other assets	2		—		—		—
	Derivative financial instruments	—		4		—		—
	Other deferred credits and other liabilities	—		2		—		—
Total		$	84	$	39	$	71	$	30

 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
Millions of dollars	2017	2016			Location	2017			2016
Three Months Ended March 31,
Interest rate contracts	—	$	(3	)	Interest expense	$	(1	)	$	(1	)

The Company:
	Loss Recognized in OCI, net of tax							Gain/(Loss) Reclassified from AOCI into Income, net of tax
Millions of dollars	2017			2016			Location	2017			2016
Three Months Ended March 31,
Interest rate contracts	—			$	(3	)	Interest expense	$	(2	)	$	(2	)
Commodity contracts	$	(2	)	(2		)	Gas purchased for resale	2			(5		)
Total	$	(2	)	$	(5	)		$	—		$	(7	)

As of March 31, 2017, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $0.6 million as a decrease to gas cost, assuming natural gas markets remain at their current levels, and approximately $6.5 million as an increase to interest expense.  As of March 31, 2017, all of the Company’s commodity cash flow hedges settle by their terms before the end of the second quarter of 2019.

As of March 31, 2017, 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 $1.7 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:
	Gain (Loss) Deferred in Regulatory Accounts						Loss Reclassified from Deferred Accounts into Income
Millions of dollars	2017		2016			Location	2017			2016
Three Months Ended March 31,
Interest rate contracts	$	11	$	(144	)	Interest Expense	$	(1	)	—

As of March 31, 2017, 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 $2.4 million as an increase to interest expense.

Credit Risk Considerations

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

Derivative Contracts with Credit Contingent Features
	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2017		December 31, 2016		March 31, 2017		December 31, 2016
in Net Liability Position
Aggregate fair value of derivatives in net liability position	$	46.0	$	50.3	$	26.4	$	30.3
Fair value of collateral already posted	30.4		29.2		9.0		9.2
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	$	15.6	$	21.1	$	17.4	$	21.1
in Net Asset Position
Aggregate fair value of derivatives in net asset position	$	69.9	$	62.9	$	69.6	$	62.0
Fair value of collateral already posted	—		—		—		—
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	$	69.9	$	62.9	$	69.6	$	62.0

In addition, for fixed price supply contracts offered to certain of SCANA Energy's customers, the Company could have called on letters of credit in the amount of $1.8 million related to $6.0 million in commodity derivatives that are in a net asset position at March 31, 2017, compared to letters of credit in the amount of $1.5 million related to derivatives of $9.0 million at December 31, 2016, 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 March 31, 2017
Gross Amounts of Recognized Assets	$	77		$	4	$	5		$	86		$	77
Gross Amounts Offset in Statement of Financial Position	—			—		(1		)	(1		)	—
Net Amounts Presented in Statement of Financial Position	77			4		4			85			77
Gross Amounts Not Offset - Financial Instruments	(8		)	—		—			(8		)	(8		)
Gross Amounts Not Offset - Cash Collateral Received	—			—		—			—			—
Net Amount	$	69		$	4	$	4		$	77		$	69
Balance sheet location
Prepayments									$	4		—
Other current assets									2			—
Other deferred debits and other assets									79			$	77
Total									$	85		$	77
As of December 31, 2016
Gross Amounts of Recognized Assets	$	71		$	9	$	10		$	90		$	71
Gross Amounts Offset in Statement of Financial Position	—			—		(4		)	(4		)	—
Net Amounts Presented in Statement of Financial Position	71			9		6			86			71
Gross Amounts Not Offset - Financial Instruments	(9		)	—		—			(9		)	(9		)
Gross Amounts Not Offset - Cash Collateral Received	—			—		—			—			—
Net Amount	$	62		$	9	$	6		$	77		$	62
Balance sheet location
Prepayments									$	9		—
Other current assets									5			—
Other deferred debits and other assets									72			$	71
Total									$	86		$	71

Derivative Liabilities	The Company										Consolidated SCE&G
Millions of dollars	Interest Rate Contracts			Commodity Contracts	Energy Management Contracts			Total			Interest Rate Contracts
As of March 31, 2017
Gross Amounts of Recognized Liabilities	$	52		—	$	5		$	57		$	34
Gross Amounts Offset in Statement of Financial Position	—			—	(1		)	(1		)	—
Net Amounts Presented in Statement of Financial Position	52			—	4			56			34
Gross Amounts Not Offset - Financial Instruments	(8		)	—	—			(8		)	(8		)
Gross Amounts Not Offset - Cash Collateral Posted	(29		)	—	(1		)	(30		)	(9		)
Net Amount	$	15		—	$	3		$	18		$	17
Balance sheet location
Derivative financial instruments								$	27		$	23
Other deferred credits and other liabilities								29			11
Total								$	56		$	34
As of December 31, 2016
Gross Amounts of Recognized Liabilities	$	58		—	$	9		$	67		$	39
Gross Amounts Offset in Statement of Financial Position	—			—	(3		)	(3		)	—
Net Amounts Presented in Statement of Financial Position	58			—	6			64			39
Gross Amounts Not Offset - Financial Instruments	(9		)	—	—			(9		)	(9		)
Gross Amounts Not Offset - Cash Collateral Posted	(29		)	—	—			(29		)	(9		)
Net Amount	$	20		—	$	6		$	26		$	21
Balance sheet location
Derivative financial instruments								$	35		$	28
Other deferred credits and other liabilities								29			11
Total								$	64		$	39

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

3 Months Ended

Mar. 31, 2017

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

Fair Value Disclosures [Text Block]

7. FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

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

	As of March 31, 2017						As of December 31, 2016
	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	$	15	—		—		$	14	—		—
Held to maturity securities	—		$	7	—		—		$	7	—
Interest rate contracts	—		77		$	77	—		71		$	71
Commodity contracts	3		1		—		8		1		—
Energy management contracts	2		3		—		6		4		—
Liabilities:
Interest rate contracts	—		52		34		—		58		39
Energy management contracts	—		8		—		2		10		—

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

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

Long-Term Debt	March 31, 2017				December 31, 2016
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
The Company	$	6,482.7	$	7,029.0	$	6,489.8	$	7,183.3
Consolidated SCE&G	5,158.7		5,606.6		5,166.0		5,752.3

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

Carrying values of short-term borrowings approximate fair value, and are based on quoted prices from dealers in the commercial paper market. The resulting fair value is considered to be Level 2.

SCEG

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

Fair Value Disclosures [Text Block]

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

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

	As of March 31, 2017						As of December 31, 2016
	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	$	15	—		—		$	14	—		—
Held to maturity securities	—		$	7	—		—		$	7	—
Interest rate contracts	—		77		$	77	—		71		$	71
Commodity contracts	3		1		—		8		1		—
Energy management contracts	2		3		—		6		4		—
Liabilities:
Interest rate contracts	—		52		34		—		58		39
Energy management contracts	—		8		—		2		10		—

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

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

Long-Term Debt	March 31, 2017				December 31, 2016
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
The Company	$	6,482.7	$	7,029.0	$	6,489.8	$	7,183.3
Consolidated SCE&G	5,158.7		5,606.6		5,166.0		5,752.3

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

Carrying values of short-term borrowings approximate fair value, and are based on quoted prices from dealers in the commercial paper market. The resulting fair value is considered to be Level 2.

XML

EMPLOYEE BENEFIT PLANS

3 Months Ended

Mar. 31, 2017

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
	2017			2016			2017		2016
Three months ended March 31,
Service cost	$	5.3		$	5.5		$	1.2	$	1.3
Interest cost	9.4			9.9			2.9		3.0
Expected return on assets	(13.8		)	(14.1		)	—		—
Prior service cost amortization	0.4			1.0			—		0.1
Amortization of actuarial losses	3.9			3.7			0.4		0.1
Net periodic benefit cost	$	5.2		$	6.0		$	4.5	$	4.5

Consolidated SCE&G	Pension Benefits						Other Postretirement Benefits
	2017			2016			2017		2016
Three months ended March 31,
Service cost	$	4.4		$	4.5		$	1.0	$	1.0
Interest cost	8.1			8.4			2.4		2.5
Expected return on assets	(11.8		)	(11.9		)	—		—
Prior service cost amortization	0.3			0.8			—		0.1
Amortization of actuarial losses	3.4			3.1			0.3		0.1
Net periodic benefit cost	$	4.4		$	4.9		$	3.7	$	3.7

No significant contribution to the pension trust is expected for the foreseeable future based on current market conditions and assumptions, 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
	2017			2016			2017		2016
Three months ended March 31,
Service cost	$	5.3		$	5.5		$	1.2	$	1.3
Interest cost	9.4			9.9			2.9		3.0
Expected return on assets	(13.8		)	(14.1		)	—		—
Prior service cost amortization	0.4			1.0			—		0.1
Amortization of actuarial losses	3.9			3.7			0.4		0.1
Net periodic benefit cost	$	5.2		$	6.0		$	4.5	$	4.5

Consolidated SCE&G	Pension Benefits						Other Postretirement Benefits
	2017			2016			2017		2016
Three months ended March 31,
Service cost	$	4.4		$	4.5		$	1.0	$	1.0
Interest cost	8.1			8.4			2.4		2.5
Expected return on assets	(11.8		)	(11.9		)	—		—
Prior service cost amortization	0.3			0.8			—		0.1
Amortization of actuarial losses	3.4			3.1			0.3		0.1
Net periodic benefit cost	$	4.4		$	4.9		$	3.7	$	3.7

No significant contribution to the pension trust is expected for the foreseeable future based on current market conditions and assumptions, nor is a limitation on benefit payments expected to apply. SCE&G recovers current pension costs through either a rate rider that may be adjusted annually for retail electric operations or through cost of service rates for gas operations.

XML

COMMITMENTS AND CONTINGENCIES

3 Months Ended

Mar. 31, 2017

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 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 $450 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 liable for up to $127.3 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $18.9 million of the liability per reactor would be assessed per year. SCE&G’s maximum assessment, based on its two-thirds ownership of Unit 1, would be $84.8 million per incident, but not more than $12.6 million per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years.

SCE&G currently maintains insurance policies (for itself and on behalf of Santee Cooper) with NEIL. The policies provide coverage to Unit 1 for property damage and outage costs up to $2.75 billion resulting from an event of nuclear origin and up to $2.33 billion resulting from an event of a non-nuclear origin. In addition, a builder's risk insurance policy has been purchased from NEIL for the construction of the New Units. This policy provides the owners of the New Units up to $500 million of total coverage for accidental property damage occurring during construction. The NEIL policies, in the aggregate, are subject to a maximum loss of $2.75 billion for any single loss occurrence. All of the NEIL policies permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $45.8 million. SCE&G currently maintains an excess property insurance policy (for itself and on behalf of Santee Cooper) with EMANI. The policy provides coverage to Unit 1 for property damage and outage costs up to $415 million resulting from an event of a non-nuclear origin. The EMANI policy permits retrospective assessments under certain conditions to cover insurer's losses. Based on the current annual premium, SCE&G's portion of the retrospective premium assessment would not exceed $1.8 million.

To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from an incident at Unit 1 exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G's rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G has no reason to anticipate a serious nuclear or other incident.  However, if such an incident were to occur, it likely would have a material impact on the Company’s and Consolidated SCE&G's results of operations, cash flows and financial position.

New Nuclear Construction

SCE&G, on behalf of itself and as agent for Santee Cooper, entered into the EPC Contract with the Consortium in 2008 for the design and construction of the New Units. SCE&G's ownership share in the New Units is 55%. As discussed below, various difficulties have been encountered in connection with the project. The ability of the construction team to adhere to established budgets and construction schedules has been affected by many variables, including unanticipated difficulties encountered in connection with project engineering and the construction of project components, constrained financial resources of the contractors, regulatory, legal, training and construction processes associated with securing approvals, permits and licenses and necessary amendments to them within projected timeframes, the availability of labor and materials at estimated costs, the efficiency of project labor and weather. There have also been contractor and supplier performance issues, difficulties in timely meeting critical regulatory requirements, contract disputes, and changes in key contractors or subcontractors. No assurance can be given that these and other construction-related difficulties will not continue to be experienced as construction progresses.

EPC Contract and BLRA Matters

The construction of the New Units and SCE&G’s related recovery of financing costs through rates is subject to review and approval by the SCPSC as provided for in the BLRA. Under the BLRA, the SCPSC has approved, among other things, a milestone schedule and a capital costs estimates schedule for the New Units. This approval constitutes a final and binding determination that the New Units are used and useful for utility purposes, and that the capital costs associated with the New Units are prudent utility costs and expenses and are properly included in rates, so long as the New Units are constructed or are being constructed within the parameters of the approved milestone schedule, including specified contingencies, and the approved capital costs estimates schedule. Subject to the same conditions, the BLRA provides that SCE&G may apply to the SCPSC annually for an order to recover through revised rates SCE&G’s weighted average cost of capital applied to all or part of the outstanding balance of construction work in progress concerning the New Units. Estimated operating costs, including the depreciation of the utility plant costs, are to be recovered through rates beginning when the construction of each New Unit is completed and it is placed into service. As of March 31, 2017, SCE&G’s investment in the New Units, including related transmission, totaled $4.6 billion, for which the financing costs on $3.8 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, and again in September 2015 and November 2016 (see discussion below), the SCPSC approved SCE&G's requested updates to the milestone schedule, revised contractual substantial completion dates, and increases in capital and other costs. It is anticipated that further approval by the SCPSC is likely to be required as a consequence of the Consortium’s bankruptcy proceedings, as further described below.

October 2015 Amendment and WEC's Engagement of Fluor

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

Among other things, the October 2015 Amendment provided SCE&G and Santee Cooper an option to fix the total amount to be paid to the Consortium for its entire scope of work on the project (excluding a limited amount of work within the time and materials component of the contract price) after June 30, 2015 at $6.082 billion (SCE&G’s 55% portion being approximately $3.345 billion). This total amount to be paid would be reduced by amounts paid since June 30, 2015. SCE&G, on behalf of itself and as agent for Santee Cooper, executed the fixed price option, subject to SCPSC approval, on July 1, 2016.

The October 2015 Amendment:

(i) resolved by settlement and release most outstanding disputes between SCE&G and the Consortium,

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

(iii) revised the delay-related liquidated damages computation requirements, including those related to the eligibility of the New Units to earn IRC Section 45J production tax credits (see also below), resulting in escalating liquidated damages that are capped at an aggregate of $338 million per New Unit (SCE&G’s 55% portion being approximately $186 million per New Unit),

(iv) provided for payment to the Consortium of a completion bonus of $150 million per New Unit (SCE&G’s 55% portion being approximately $83 million per New Unit) for each New Unit placed in service by the deadline to qualify for production tax credits,

(v) provided for development of a revised construction milestone payment schedule,

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

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

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

November 2016 SCPSC Order

In May 2016, SCE&G petitioned the SCPSC for approval of updated construction and capital cost schedules for the New Units which were developed in connection with the October 2015 Amendment. On November 9, 2016, the SCPSC approved a settlement agreement among SCE&G, ORS and certain other parties concerning this petition. The SCPSC also approved SCE&G's election of the fixed price option.

The construction schedule approved by the SCPSC in November 2016 provided for contractual guaranteed substantial completion dates of August 31, 2019 and August 31, 2020 for Units 2 and 3, respectively. The approved capital cost schedule includes incremental capital costs that total $831 million. Under such approved capital cost schedule, SCE&G’s total project capital cost would be approximately $6.8 billion including owner’s costs and transmission, or $7.7 billion with escalation and AFC. In addition, the SCPSC approved revising SCE&G’s allowed ROE for new nuclear construction from 10.5% to 10.25%. This revised ROE will be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2017. In addition, SCE&G may not file future requests to amend capital cost schedules prior to January 28, 2019, unless its annual revised rate request is denied because SCE&G is out of compliance with its approved capital cost schedule or BLRA construction milestone schedule. In most circumstances, if the projected commercial operation date for Unit 2 is extended, the expiration of the January 28, 2019 moratorium will be extended by an equal amount of time. Finally, following the expiration of the January 28, 2019 moratorium, SCE&G's right to file future budget increase requests with the SCPSC is limited in certain circumstances to the extent those requests are not associated with change orders, DRB orders, transmission costs, certain time and materials costs, and certain owners’ costs.

On February 28, 2017, the SCPSC issued its order denying the Petitions for Rehearing filed by certain parties that were not included in the settlement. The time period to file a Notice of Appeal of the SCPSC’s decision with the South Carolina Supreme Court has expired for three of the four non-settling parties, and none of those parties has filed a Notice of Appeal.  The remaining non-settling party has until May 8, 2017, to file a Notice of Appeal.

DRB Activity

The October 2015 Amendment established a DRB process for resolving certain commercial claims and disputes. The DRB is comprised of three members chosen by the parties and, under the DRB process, amounts in dispute of less than $5 million are to be resolved by the DRB without recourse. Amounts in dispute greater than $5 million are to be resolved by the DRB for the remainder of the construction of the New Units, with a reserved right to further arbitrate or to litigate such issues at the conclusion of construction.

On February 24, 2017, following SCE&G’s nonpayment of certain invoices upon its assertion that WEC had not fulfilled documentation requirements imposed by the DRB, WEC referred a related claim to the DRB. SCE&G then provided the DRB a response and WEC in turn provided its rebuttal; however, following the Consortium’s bankruptcy filing on March 29, 2017, action regarding this DRB referral ceased.

Payment and Performance Obligations, Contractor Bankruptcy Proceedings and Related Uncertainties

Payment and performance obligations under the EPC Contract are joint and several obligations of WEC and WECTEC, and in connection with the October 2015 Amendment, Toshiba, WEC’s parent company, reaffirmed its guaranty of WEC’s payment obligations. Additionally, the EPC Contract provides the owners the right, exercisable upon certain conditions, to obtain payment and performance bonds from WEC equal to 15%of the highest projected three months' billings during the applicable year, and their aggregate nominal coverage will not 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 obtained annual 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 automatically renew for successive one-year periods until their final expiration date of August 31, 2020, unless the issuer provides a minimum 60-day notice that it will not renew. If the issuer provides notice that it will not renew, SCE&G may draw upon the standby letter of credit prior to its expiration. In the event that WEC were not to meet its payment and performance obligations under the EPC Contract, it is anticipated that this funding would provide a source of liquidity. In addition, the EPC Contract provides that upon the request of SCE&G, and at owners' cost, the Consortium must escrow certain intellectual property and software for the owners' benefit to assist in completion of the New Units. An escrow arrangement has been established, andWEC has reported that substantially all of the required intellectual property and software have been deposited. SCE&G is attempting to verify that this information is present in useable form.

On March 29, 2017, WEC and WECTEC, the two members of the Consortium, and certain of their affiliates filed petitions for protection under Chapter 11 of the U.S. Bankruptcy Code, citing a liquidity crisis arising from project contract losses attributable to the New Units and the Vogtle Units as a material factor that caused them to seek protection under the bankruptcy laws. In connection with the filing, SCE&G, Santee Cooper, WEC and WECTEC entered into the Interim Assessment Agreement which, as amended, expires on June 26, 2017 unless otherwise terminated. Under the terms of the Interim Assessment Agreement and while it remains in effect, all parties have agreed to continue to perform under the EPC Contract and to give SCE&G and Santee Cooper the right to discuss project status with Fluor and other subcontractors and vendors and to obtain relevant project information and documents from them. SCE&G and Santee Cooper are obligated to pay all costs incurred by the Consortium, Fluor, other subcontractors and vendors for work performed or services rendered while the Interim Assessment Agreement remains in effect. SCE&G and Santee Cooper have also agreed not to draw on the letters of credit discussed above so long as the Interim Assessment Agreement is in effect.

In April of 2017, Toshiba, following several announcements and media reports and following WEC’s and WECTEC’s bankruptcy petitions, announced that it had recorded an impairment charge of approximately $6.2 billion relating to its nuclear power systems business, leaving it with negative shareholders’ equity. Toshiba also disclosed that, although these conditions and events raise substantial doubt, it believed that its responses to such conditions, including the sale of a portion of its computer memory business as then anticipated by Toshiba, would enable it to continue to operate as a going concern. Additionally, Toshiba indicated that it intends to significantly alter its risk management oversight of its nuclear business, and in its filings with the Bankruptcy Court, the Consortium stated that it intends to discontinue its role in the construction of nuclear plants. However, there can be no assurance that such sales or other actions will be successful. As such, there can be no assurance that Toshiba will fulfill its payment guaranty obligations under the EPC Contract.

In February 2017, WEC notified the Company and Consolidated SCE&G that the contractual guaranteed substantial completion dates of August 2019 and 2020 for Unit 2 and Unit 3, respectively, which were reflected in the October 2015 Amendment, are not likely to be met. Instead, WEC provided further revised estimated substantial completion dates of April 2020 and December 2020. These later dates remain within the SCPSC-approved 18-month contingency periods provided for under the BLRA, and achievement of such dates would also allow the output of both units to qualify, under current law, for federal production tax credits (see below). However, there can be no assurance that these dates will be achieved in light of WEC’s historical inability to achieve forecasted productivity and work force efficiency levels and in light of the Consortium’s bankruptcy filing.

Pursuant to the Interim Assessment Agreement, SCE&G and Santee Cooper are evaluating the various elements of the project, including forecasted costs and completion dates, while construction continues and SCE&G and Santee Cooper continue to make payments for such work. The initial term of the Interim Assessment Agreement was 30 days and it has been amended to extend its term through June 26, 2017; however, it may also be terminated earlier by SCE&G or Santee Cooper. Any decision to further extend the Interim Assessment Agreement may be impacted by the willingness of the other parties thereto. Termination of the Interim Assessment Agreement prior to such time that SCE&G and Santee Cooper have completed a full evaluation may adversely impact the continuation of construction of the project.

If, as a result of the bankruptcy process, the benefit of the fixed-price terms provided by the EPC Contract is lost, and part or all of the cost overruns expected to be incurred by the Consortium become the responsibility of SCE&G and Santee Cooper, these cost increases may or may not be recoverable from the Consortium or from Toshiba under its payment guaranty, or may materially exceed the amount of the Consortium's payment obligations guaranteed by Toshiba, which in general are limited to 25 percent of the payments made to the Consortium at the time of its breach under the EPC Contract. The ability of SCE&G to recover any increased costs through rates will be subject to review and approval by the SCPSC, and such costs may or may not qualify for recovery under the BLRA. For example, certain parties may challenge such costs as not being subject to recovery under the BLRA as a result of the terms of the settlement agreement approved by the SCPSC on November 9, 2016.

If, as part of the bankruptcy process, the EPC Contract is rejected, then SCE&G and Santee Cooper will need to engage replacement contractors and/or assume responsibilities of the contractor under the EPC Contract in order to complete the New Units. Alternatively, SCE&G and Santee Cooper could also decide to abandon the construction of one or both of the New Units, leaving SCE&G to pursue cost recovery under the abandonment provisions of the BLRA.

The Consortium has agreed not to reject the EPC Contract prior to the date of termination of the Interim Assessment Agreement; however, after the end of the term of the Interim Assessment Agreement, it is likely that the EPC Contract will be rejected. If the EPC Contract is rejected during the bankruptcy process, it is unlikely that SCE&G and Santee Cooper will be able to negotiate replacement contracts on similar terms with members of the Consortium, and there can be no assurance that some or all of the members of the Consortium will have roles in connection with the design, engineering or construction of the New Units. Additionally, there can be no assurance that any such replacement contracts will provide protection against future construction cost increases through a negotiated fixed price or that they will not assign some or all of the risks for escalating costs onto the owners. There also can be no assurance that SCE&G and Santee Cooper will be able to complete the construction of the New Units without significant delay or additional costs, should they decide to move forward with the project. Such delays could result in the loss of qualification for production tax credits referred to above and disclosed below.

A number of subcontractors and vendors to the Consortium, including Fluor, have alleged non-payment by the Consortium for amounts owed for work performed on the New Units.  SCE&G is contesting the filed liens.  SCE&G estimates that the aggregate amount of claims for which subcontractor and vendor liens have been filed is approximately $118 million (SCE&G’s 55% portion being approximately $65 million), of which $50 million (SCE&G’s 55% share being $27.5 million) have been paid.  SCE&G will continue to evaluate the issues relating to these claims during the pendency of the bankruptcy proceeding.

Jointly-owned projects, such as the current construction of the New Units, are also subject to risks such as (1) one or more of the joint owners becoming either unable or unwilling to continue to fund project financial commitments, (2) new joint owners being sought but not being secured at equivalent financial terms, or (3) disagreement among joint owners or changes in the joint ownership make-up which further increase project costs, further delay the completion of the project or result in the termination of all or a portion of the project.

The Consortium’s bankruptcy filing could have a material impact on the construction of the New Units and could have a material impact on SCANA’s and SCE&G’s results of operations, cash flows and financial condition. The ultimate outcome of these matters cannot be determined at this time.

Santee Cooper Matters

SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper. Under the terms of this agreement, SCE&G will acquire a 1% ownership interest in the New Units at the commercial operation date of Unit 2, an additional 2% ownership interest no later than the first anniversary of such commercial operation date, and the final 2% no later than the second anniversary of such commercial operation date. SCE&G has agreed to pay an amount equal to Santee Cooper's actual cost, including its cost of financing, of the percentage conveyed as of the date of each conveyance. In addition, the agreement provides that Santee Cooper will not transfer any of its remaining interest in the New Units to third parties until the New Units are complete. This transaction is subject to customary closing conditions, including receipt of necessary regulatory approvals. This transaction will not affect the payment obligations between the parties during construction of the New Units, nor is it anticipated that the payments for the additional ownership interest would be reflected in a revised rates filing under the BLRA. SCE&G’s projected cost for the additional 5% interest being acquired from Santee Cooper was approximately $850 million at December 31, 2016, and is being further evaluated.

Nuclear Production Tax Credits

The IRS has notified SCE&G that, subject to a national megawatt capacity limitation, the electricity to be produced by each of the New Units (advanced nuclear units, as defined) would qualify for nuclear production tax credits under Section 45J of the IRC to the extent that such New Unit is operational before January 1, 2021 and other eligibility requirements are met. These nuclear production tax credits (related to SCE&G's 55% share of both New Units) could total as much as approximately $1.4 billion. Such credits would be earned over the first eight years of each New Unit's operations and would be realized by SCE&G over those years or during allowable carry-forward periods. Based on current tax law and the contractual guaranteed substantial completion dates (and the dates of completion forecasted by WEC in February 2017) provided above, both New Units would be operational and would qualify for the nuclear production tax credits; however, any further delays in the schedule or changes in tax law could adversely impact these conclusions. See also the Payment and Performance Obligations, Contractor Bankruptcy Proceedings and Related Uncertainties discussion above. When and to the extent that production tax credits are realized, their benefits are expected to be provided directly to SCE&G's electric customers.

During March 2017, legislation was introduced in both houses of Congress which would eliminate the requirement that the New Units be operational before January 1, 2021 in order for their electricity production to qualify for the nuclear production tax credits; however, there can be no assurance that such legislation will become law.

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 CO₂ 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 its SIP, 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. As a result of an Executive Order on March 28, 2017, the EPA is reconsidering the rule and the Court of Appeals agreed to hold the case in abeyance for 60 days. The Company and Consolidated SCE&G expect any costs incurred to comply with such rule to be recoverable through rates.

In July 2011, the EPA issued the CSAPR to reduce emissions of SO₂ and NO_X from power plants in the eastern half of the United States. The CSAPR replaces the CAIR and requires a total of 28 states to reduce annual SO₂ emissions and annual and ozone season NO_X emissions to assist in attaining the ozone and fine particle NAAQS. The rule establishes an emissions cap for SO₂ and NO_X and limits the trading for emission allowances by separating affected states into two groups with no trading between the groups. The State of South Carolina has chosen to remain in the CSAPR program, even though recent court rulings exempted the state. This allows the state to remain compliant with regional haze standards. Air quality control installations that SCE&G and GENCO have already completed have positioned them to comply with the existing allowances set by the CSAPR. Any costs incurred to comply with CSAPR are expected to be recoverable through rates.

In April 2012, the EPA's MATS rule containing new standards for mercury and other specified air pollutants became effective. The MATS rule has been the subject of ongoing litigation even while it remains in effect. Rulings on this litigation are not expected to have an impact on SCE&G or GENCO due to plant retirements, conversions, and enhancements. SCE&G and GENCO are in compliance with the MATS rule and expect to remain in compliance.

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

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 2018 and will cost an additional $10.1 million, which is accrued in Other within Deferred Credits and Other Liabilities on the consolidated balance sheet. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates. At March 31, 2017, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $25.3 million and are included in regulatory assets.

SCEG

Statement [Line Items]

Commitments and Contingencies Disclosure [Text Block]

COMMITMENTS AND CONTINGENCIES

Nuclear Insurance

Under Price-Anderson, SCE&G (for itself and on behalf of Santee Cooper, a one-third owner of 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 $450 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 liable for up to $127.3 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $18.9 million of the liability per reactor would be assessed per year. SCE&G’s maximum assessment, based on its two-thirds ownership of Unit 1, would be $84.8 million per incident, but not more than $12.6 million per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years.

SCE&G currently maintains insurance policies (for itself and on behalf of Santee Cooper) with NEIL. The policies provide coverage to Unit 1 for property damage and outage costs up to $2.75 billion resulting from an event of nuclear origin and up to $2.33 billion resulting from an event of a non-nuclear origin. In addition, a builder's risk insurance policy has been purchased from NEIL for the construction of the New Units. This policy provides the owners of the New Units up to $500 million of total coverage for accidental property damage occurring during construction. The NEIL policies, in the aggregate, are subject to a maximum loss of $2.75 billion for any single loss occurrence. All of the NEIL policies permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $45.8 million. SCE&G currently maintains an excess property insurance policy (for itself and on behalf of Santee Cooper) with EMANI. The policy provides coverage to Unit 1 for property damage and outage costs up to $415 million resulting from an event of a non-nuclear origin. The EMANI policy permits retrospective assessments under certain conditions to cover insurer's losses. Based on the current annual premium, SCE&G's portion of the retrospective premium assessment would not exceed $1.8 million.

To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from an incident at Unit 1 exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G's rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G has no reason to anticipate a serious nuclear or other incident.  However, if such an incident were to occur, it likely would have a material impact on the Company’s and Consolidated SCE&G's results of operations, cash flows and financial position.

New Nuclear Construction

SCE&G, on behalf of itself and as agent for Santee Cooper, entered into the EPC Contract with the Consortium in 2008 for the design and construction of the New Units. SCE&G's ownership share in the New Units is 55%. As discussed below, various difficulties have been encountered in connection with the project. The ability of the construction team to adhere to established budgets and construction schedules has been affected by many variables, including unanticipated difficulties encountered in connection with project engineering and the construction of project components, constrained financial resources of the contractors, regulatory, legal, training and construction processes associated with securing approvals, permits and licenses and necessary amendments to them within projected timeframes, the availability of labor and materials at estimated costs, the efficiency of project labor and weather. There have also been contractor and supplier performance issues, difficulties in timely meeting critical regulatory requirements, contract disputes, and changes in key contractors or subcontractors. No assurance can be given that these and other construction-related difficulties will not continue to be experienced as construction progresses.

EPC Contract and BLRA Matters

The construction of the New Units and SCE&G’s related recovery of financing costs through rates is subject to review and approval by the SCPSC as provided for in the BLRA. Under the BLRA, the SCPSC has approved, among other things, a milestone schedule and a capital costs estimates schedule for the New Units. This approval constitutes a final and binding determination that the New Units are used and useful for utility purposes, and that the capital costs associated with the New Units are prudent utility costs and expenses and are properly included in rates, so long as the New Units are constructed or are being constructed within the parameters of the approved milestone schedule, including specified contingencies, and the approved capital costs estimates schedule. Subject to the same conditions, the BLRA provides that SCE&G may apply to the SCPSC annually for an order to recover through revised rates SCE&G’s weighted average cost of capital applied to all or part of the outstanding balance of construction work in progress concerning the New Units. Estimated operating costs, including the depreciation of the utility plant costs, are to be recovered through rates beginning when the construction of each New Unit is completed and it is placed into service. As of March 31, 2017, SCE&G’s investment in the New Units, including related transmission, totaled $4.6 billion, for which the financing costs on $3.8 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, and again in September 2015 and November 2016 (see discussion below), the SCPSC approved SCE&G's requested updates to the milestone schedule, revised contractual substantial completion dates, and increases in capital and other costs. It is anticipated that further approval by the SCPSC is likely to be required as a consequence of the Consortium’s bankruptcy proceedings, as further described below.

October 2015 Amendment and WEC's Engagement of Fluor

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

Among other things, the October 2015 Amendment provided SCE&G and Santee Cooper an option to fix the total amount to be paid to the Consortium for its entire scope of work on the project (excluding a limited amount of work within the time and materials component of the contract price) after June 30, 2015 at $6.082 billion (SCE&G’s 55% portion being approximately $3.345 billion). This total amount to be paid would be reduced by amounts paid since June 30, 2015. SCE&G, on behalf of itself and as agent for Santee Cooper, executed the fixed price option, subject to SCPSC approval, on July 1, 2016.

The October 2015 Amendment:

(i) resolved by settlement and release most outstanding disputes between SCE&G and the Consortium,

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

(iii) revised the delay-related liquidated damages computation requirements, including those related to the eligibility of the New Units to earn IRC Section 45J production tax credits (see also below), resulting in escalating liquidated damages that are capped at an aggregate of $338 million per New Unit (SCE&G’s 55% portion being approximately $186 million per New Unit),

(iv) provided for payment to the Consortium of a completion bonus of $150 million per New Unit (SCE&G’s 55% portion being approximately $83 million per New Unit) for each New Unit placed in service by the deadline to qualify for production tax credits,

(v) provided for development of a revised construction milestone payment schedule,

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

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

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

November 2016 SCPSC Order

In May 2016, SCE&G petitioned the SCPSC for approval of updated construction and capital cost schedules for the New Units which were developed in connection with the October 2015 Amendment. On November 9, 2016, the SCPSC approved a settlement agreement among SCE&G, ORS and certain other parties concerning this petition. The SCPSC also approved SCE&G's election of the fixed price option.

The construction schedule approved by the SCPSC in November 2016 provided for contractual guaranteed substantial completion dates of August 31, 2019 and August 31, 2020 for Units 2 and 3, respectively. The approved capital cost schedule includes incremental capital costs that total $831 million. Under such approved capital cost schedule, SCE&G’s total project capital cost would be approximately $6.8 billion including owner’s costs and transmission, or $7.7 billion with escalation and AFC. In addition, the SCPSC approved revising SCE&G’s allowed ROE for new nuclear construction from 10.5% to 10.25%. This revised ROE will be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2017. In addition, SCE&G may not file future requests to amend capital cost schedules prior to January 28, 2019, unless its annual revised rate request is denied because SCE&G is out of compliance with its approved capital cost schedule or BLRA construction milestone schedule. In most circumstances, if the projected commercial operation date for Unit 2 is extended, the expiration of the January 28, 2019 moratorium will be extended by an equal amount of time. Finally, following the expiration of the January 28, 2019 moratorium, SCE&G's right to file future budget increase requests with the SCPSC is limited in certain circumstances to the extent those requests are not associated with change orders, DRB orders, transmission costs, certain time and materials costs, and certain owners’ costs.

On February 28, 2017, the SCPSC issued its order denying the Petitions for Rehearing filed by certain parties that were not included in the settlement. The time period to file a Notice of Appeal of the SCPSC’s decision with the South Carolina Supreme Court has expired for three of the four non-settling parties, and none of those parties has filed a Notice of Appeal.  The remaining non-settling party has until May 8, 2017, to file a Notice of Appeal.

DRB Activity

The October 2015 Amendment established a DRB process for resolving certain commercial claims and disputes. The DRB is comprised of three members chosen by the parties and, under the DRB process, amounts in dispute of less than $5 million are to be resolved by the DRB without recourse. Amounts in dispute greater than $5 million are to be resolved by the DRB for the remainder of the construction of the New Units, with a reserved right to further arbitrate or to litigate such issues at the conclusion of construction.

On February 24, 2017, following SCE&G’s nonpayment of certain invoices upon its assertion that WEC had not fulfilled documentation requirements imposed by the DRB, WEC referred a related claim to the DRB. SCE&G then provided the DRB a response and WEC in turn provided its rebuttal; however, following the Consortium’s bankruptcy filing on March 29, 2017, action regarding this DRB referral ceased.

Payment and Performance Obligations, Contractor Bankruptcy Proceedings and Related Uncertainties

Payment and performance obligations under the EPC Contract are joint and several obligations of WEC and WECTEC, and in connection with the October 2015 Amendment, Toshiba, WEC’s parent company, reaffirmed its guaranty of WEC’s payment obligations. Additionally, the EPC Contract provides the owners the right, exercisable upon certain conditions, to obtain payment and performance bonds from WEC equal to 15%of the highest projected three months' billings during the applicable year, and their aggregate nominal coverage will not 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 obtained annual 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 automatically renew for successive one-year periods until their final expiration date of August 31, 2020, unless the issuer provides a minimum 60-day notice that it will not renew. If the issuer provides notice that it will not renew, SCE&G may draw upon the standby letter of credit prior to its expiration. In the event that WEC were not to meet its payment and performance obligations under the EPC Contract, it is anticipated that this funding would provide a source of liquidity. In addition, the EPC Contract provides that upon the request of SCE&G, and at owners' cost, the Consortium must escrow certain intellectual property and software for the owners' benefit to assist in completion of the New Units. An escrow arrangement has been established, andWEC has reported that substantially all of the required intellectual property and software have been deposited. SCE&G is attempting to verify that this information is present in useable form.

On March 29, 2017, WEC and WECTEC, the two members of the Consortium, and certain of their affiliates filed petitions for protection under Chapter 11 of the U.S. Bankruptcy Code, citing a liquidity crisis arising from project contract losses attributable to the New Units and the Vogtle Units as a material factor that caused them to seek protection under the bankruptcy laws. In connection with the filing, SCE&G, Santee Cooper, WEC and WECTEC entered into the Interim Assessment Agreement which, as amended, expires on June 26, 2017 unless otherwise terminated. Under the terms of the Interim Assessment Agreement and while it remains in effect, all parties have agreed to continue to perform under the EPC Contract and to give SCE&G and Santee Cooper the right to discuss project status with Fluor and other subcontractors and vendors and to obtain relevant project information and documents from them. SCE&G and Santee Cooper are obligated to pay all costs incurred by the Consortium, Fluor, other subcontractors and vendors for work performed or services rendered while the Interim Assessment Agreement remains in effect. SCE&G and Santee Cooper have also agreed not to draw on the letters of credit discussed above so long as the Interim Assessment Agreement is in effect.

In April of 2017, Toshiba, following several announcements and media reports and following WEC’s and WECTEC’s bankruptcy petitions, announced that it had recorded an impairment charge of approximately $6.2 billion relating to its nuclear power systems business, leaving it with negative shareholders’ equity. Toshiba also disclosed that, although these conditions and events raise substantial doubt, it believed that its responses to such conditions, including the sale of a portion of its computer memory business as then anticipated by Toshiba, would enable it to continue to operate as a going concern. Additionally, Toshiba indicated that it intends to significantly alter its risk management oversight of its nuclear business, and in its filings with the Bankruptcy Court, the Consortium stated that it intends to discontinue its role in the construction of nuclear plants. However, there can be no assurance that such sales or other actions will be successful. As such, there can be no assurance that Toshiba will fulfill its payment guaranty obligations under the EPC Contract.

In February 2017, WEC notified the Company and Consolidated SCE&G that the contractual guaranteed substantial completion dates of August 2019 and 2020 for Unit 2 and Unit 3, respectively, which were reflected in the October 2015 Amendment, are not likely to be met. Instead, WEC provided further revised estimated substantial completion dates of April 2020 and December 2020. These later dates remain within the SCPSC-approved 18-month contingency periods provided for under the BLRA, and achievement of such dates would also allow the output of both units to qualify, under current law, for federal production tax credits (see below). However, there can be no assurance that these dates will be achieved in light of WEC’s historical inability to achieve forecasted productivity and work force efficiency levels and in light of the Consortium’s bankruptcy filing.

Pursuant to the Interim Assessment Agreement, SCE&G and Santee Cooper are evaluating the various elements of the project, including forecasted costs and completion dates, while construction continues and SCE&G and Santee Cooper continue to make payments for such work. The initial term of the Interim Assessment Agreement was 30 days and it has been amended to extend its term through June 26, 2017; however, it may also be terminated earlier by SCE&G or Santee Cooper. Any decision to further extend the Interim Assessment Agreement may be impacted by the willingness of the other parties thereto. Termination of the Interim Assessment Agreement prior to such time that SCE&G and Santee Cooper have completed a full evaluation may adversely impact the continuation of construction of the project.

If, as a result of the bankruptcy process, the benefit of the fixed-price terms provided by the EPC Contract is lost, and part or all of the cost overruns expected to be incurred by the Consortium become the responsibility of SCE&G and Santee Cooper, these cost increases may or may not be recoverable from the Consortium or from Toshiba under its payment guaranty, or may materially exceed the amount of the Consortium's payment obligations guaranteed by Toshiba, which in general are limited to 25 percent of the payments made to the Consortium at the time of its breach under the EPC Contract. The ability of SCE&G to recover any increased costs through rates will be subject to review and approval by the SCPSC, and such costs may or may not qualify for recovery under the BLRA. For example, certain parties may challenge such costs as not being subject to recovery under the BLRA as a result of the terms of the settlement agreement approved by the SCPSC on November 9, 2016.

If, as part of the bankruptcy process, the EPC Contract is rejected, then SCE&G and Santee Cooper will need to engage replacement contractors and/or assume responsibilities of the contractor under the EPC Contract in order to complete the New Units. Alternatively, SCE&G and Santee Cooper could also decide to abandon the construction of one or both of the New Units, leaving SCE&G to pursue cost recovery under the abandonment provisions of the BLRA.

The Consortium has agreed not to reject the EPC Contract prior to the date of termination of the Interim Assessment Agreement; however, after the end of the term of the Interim Assessment Agreement, it is likely that the EPC Contract will be rejected. If the EPC Contract is rejected during the bankruptcy process, it is unlikely that SCE&G and Santee Cooper will be able to negotiate replacement contracts on similar terms with members of the Consortium, and there can be no assurance that some or all of the members of the Consortium will have roles in connection with the design, engineering or construction of the New Units. Additionally, there can be no assurance that any such replacement contracts will provide protection against future construction cost increases through a negotiated fixed price or that they will not assign some or all of the risks for escalating costs onto the owners. There also can be no assurance that SCE&G and Santee Cooper will be able to complete the construction of the New Units without significant delay or additional costs, should they decide to move forward with the project. Such delays could result in the loss of qualification for production tax credits referred to above and disclosed below.

A number of subcontractors and vendors to the Consortium, including Fluor, have alleged non-payment by the Consortium for amounts owed for work performed on the New Units.  SCE&G is contesting the filed liens.  SCE&G estimates that the aggregate amount of claims for which subcontractor and vendor liens have been filed is approximately $118 million (SCE&G’s 55% portion being approximately $65 million), of which $50 million (SCE&G’s 55% share being $27.5 million) have been paid.  SCE&G will continue to evaluate the issues relating to these claims during the pendency of the bankruptcy proceeding.

Jointly-owned projects, such as the current construction of the New Units, are also subject to risks such as (1) one or more of the joint owners becoming either unable or unwilling to continue to fund project financial commitments, (2) new joint owners being sought but not being secured at equivalent financial terms, or (3) disagreement among joint owners or changes in the joint ownership make-up which further increase project costs, further delay the completion of the project or result in the termination of all or a portion of the project.

The Consortium’s bankruptcy filing could have a material impact on the construction of the New Units and could have a material impact on SCANA’s and SCE&G’s results of operations, cash flows and financial condition. The ultimate outcome of these matters cannot be determined at this time.

Santee Cooper Matters

SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper. Under the terms of this agreement, SCE&G will acquire a 1% ownership interest in the New Units at the commercial operation date of Unit 2, an additional 2% ownership interest no later than the first anniversary of such commercial operation date, and the final 2% no later than the second anniversary of such commercial operation date. SCE&G has agreed to pay an amount equal to Santee Cooper's actual cost, including its cost of financing, of the percentage conveyed as of the date of each conveyance. In addition, the agreement provides that Santee Cooper will not transfer any of its remaining interest in the New Units to third parties until the New Units are complete. This transaction is subject to customary closing conditions, including receipt of necessary regulatory approvals. This transaction will not affect the payment obligations between the parties during construction of the New Units, nor is it anticipated that the payments for the additional ownership interest would be reflected in a revised rates filing under the BLRA. SCE&G’s projected cost for the additional 5% interest being acquired from Santee Cooper was approximately $850 million at December 31, 2016, and is being further evaluated.

Nuclear Production Tax Credits

The IRS has notified SCE&G that, subject to a national megawatt capacity limitation, the electricity to be produced by each of the New Units (advanced nuclear units, as defined) would qualify for nuclear production tax credits under Section 45J of the IRC to the extent that such New Unit is operational before January 1, 2021 and other eligibility requirements are met. These nuclear production tax credits (related to SCE&G's 55% share of both New Units) could total as much as approximately $1.4 billion. Such credits would be earned over the first eight years of each New Unit's operations and would be realized by SCE&G over those years or during allowable carry-forward periods. Based on current tax law and the contractual guaranteed substantial completion dates (and the dates of completion forecasted by WEC in February 2017) provided above, both New Units would be operational and would qualify for the nuclear production tax credits; however, any further delays in the schedule or changes in tax law could adversely impact these conclusions. See also the Payment and Performance Obligations, Contractor Bankruptcy Proceedings and Related Uncertainties discussion above. When and to the extent that production tax credits are realized, their benefits are expected to be provided directly to SCE&G's electric customers.

During March 2017, legislation was introduced in both houses of Congress which would eliminate the requirement that the New Units be operational before January 1, 2021 in order for their electricity production to qualify for the nuclear production tax credits; however, there can be no assurance that such legislation will become law.

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 CO₂ 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 its SIP, 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. As a result of an Executive Order on March 28, 2017, the EPA is reconsidering the rule and the Court of Appeals agreed to hold the case in abeyance for 60 days. The Company and Consolidated SCE&G expect any costs incurred to comply with such rule to be recoverable through rates.

In July 2011, the EPA issued the CSAPR to reduce emissions of SO₂ and NO_X from power plants in the eastern half of the United States. The CSAPR replaces the CAIR and requires a total of 28 states to reduce annual SO₂ emissions and annual and ozone season NO_X emissions to assist in attaining the ozone and fine particle NAAQS. The rule establishes an emissions cap for SO₂ and NO_X and limits the trading for emission allowances by separating affected states into two groups with no trading between the groups. The State of South Carolina has chosen to remain in the CSAPR program, even though recent court rulings exempted the state. This allows the state to remain compliant with regional haze standards. Air quality control installations that SCE&G and GENCO have already completed have positioned them to comply with the existing allowances set by the CSAPR. Any costs incurred to comply with CSAPR are expected to be recoverable through rates.

In April 2012, the EPA's MATS rule containing new standards for mercury and other specified air pollutants became effective. The MATS rule has been the subject of ongoing litigation even while it remains in effect. Rulings on this litigation are not expected to have an impact on SCE&G or GENCO due to plant retirements, conversions, and enhancements. SCE&G and GENCO are in compliance with the MATS rule and expect to remain in compliance.

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

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 2018 and will cost an additional $10.1 million, which is accrued in Other within Deferred Credits and Other Liabilities on the consolidated balance sheet. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates. At March 31, 2017, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $25.3 million and are included in regulatory assets.

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SEGMENT OF BUSINESS INFORMATION

3 Months Ended

Mar. 31, 2017

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. The Gas Marketing segment measures 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.

The Company
Millions of dollars	External Revenue		Intersegment Revenue			Operating Income		Net Income
Three Months Ended March 31, 2017
Electric Operations	$	577	$	1		$	178	n/a
Gas Distribution	322		—			113		n/a
Gas Marketing	274		24			n/a		$	15
All Other	—		94			—		—
Adjustments/Eliminations	—		(119		)	25		156
Consolidated Total	$	1,173	$	—		$	316	$	171

Three Months Ended March 31, 2016
Electric Operations	$	592	$	1		$	198	n/a
Gas Distribution	299		1			94		n/a
Gas Marketing	281		22			n/a		$	24
All Other	—		98			—		—
Adjustments/Eliminations	—		(122		)	39		152
Consolidated Total	$	1,172	$	—		$	331	$	176

Consolidated SCE&G
Millions of dollars	External Revenue		Operating Income		Earnings Available to Common Shareholder
Three Months Ended March 31, 2017
Electric Operations	$	578	$	178	n/a
Gas Distribution	141		44		n/a
Adjustments/Eliminations	—		—		$	109
Consolidated Total	$	719	$	222	$	109

Three Months Ended March 31, 2016
Electric Operations	$	593	$	198	n/a
Gas Distribution	124		38		n/a
Adjustments/Eliminations	—		—		$	113
Consolidated Total	$	717	$	236	$	113

Segment Assets	The Company				Consolidated SCE&G
	March 31,		December 31,		March 31,		December 31,
Millions of dollars	2017		2016		2017		2016
Electric Operations	$	12,076	$	11,929	$	12,076	$	11,929
Gas Distribution	2,926		2,892		836		825
Gas Marketing	202		230		n/a		n/a
All Other	997		1,124		n/a		n/a
Adjustments/Eliminations	2,257		2,532		3,053		3,337
Consolidated Total	$	18,458	$	18,707	$	15,965	$	16,091

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. The Gas Marketing segment measures 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.

The Company
Millions of dollars	External Revenue		Intersegment Revenue			Operating Income		Net Income
Three Months Ended March 31, 2017
Electric Operations	$	577	$	1		$	178	n/a
Gas Distribution	322		—			113		n/a
Gas Marketing	274		24			n/a		$	15
All Other	—		94			—		—
Adjustments/Eliminations	—		(119		)	25		156
Consolidated Total	$	1,173	$	—		$	316	$	171

Three Months Ended March 31, 2016
Electric Operations	$	592	$	1		$	198	n/a
Gas Distribution	299		1			94		n/a
Gas Marketing	281		22			n/a		$	24
All Other	—		98			—		—
Adjustments/Eliminations	—		(122		)	39		152
Consolidated Total	$	1,172	$	—		$	331	$	176

Consolidated SCE&G
Millions of dollars	External Revenue		Operating Income		Earnings Available to Common Shareholder
Three Months Ended March 31, 2017
Electric Operations	$	578	$	178	n/a
Gas Distribution	141		44		n/a
Adjustments/Eliminations	—		—		$	109
Consolidated Total	$	719	$	222	$	109

Three Months Ended March 31, 2016
Electric Operations	$	593	$	198	n/a
Gas Distribution	124		38		n/a
Adjustments/Eliminations	—		—		$	113
Consolidated Total	$	717	$	236	$	113

Segment Assets	The Company				Consolidated SCE&G
	March 31,		December 31,		March 31,		December 31,
Millions of dollars	2017		2016		2017		2016
Electric Operations	$	12,076	$	11,929	$	12,076	$	11,929
Gas Distribution	2,926		2,892		836		825
Gas Marketing	202		230		n/a		n/a
All Other	997		1,124		n/a		n/a
Adjustments/Eliminations	2,257		2,532		3,053		3,337
Consolidated Total	$	18,458	$	18,707	$	15,965	$	16,091

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AFFILIATED TRANSACTIONS

3 Months Ended

Mar. 31, 2017

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.  Consolidated SCE&G’s total purchases from this affiliate were $44.6 million and $52.8 million for the three months ended March 31, 2017 and 2016, respectively. Consolidated SCE&G’s total sales to this affiliate were $44.4 million and $52.5 million for the three months ended March 31, 2017 and 2016, respectively. The net of the total purchases and total sales are recorded in Other expenses on the condensed consolidated statements of income (for the Company) and of comprehensive income (for Consolidated SCE&G). Consolidated SCE&G’s receivable from this affiliate was $13.5 million at March 31, 2017 and $16.0 million at December 31, 2016.  Consolidated SCE&G’s payable to this affiliate was $13.6 million at March 31, 2017 and $16.1 million at December 31, 2016.

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.  Consolidated SCE&G’s total purchases from this affiliate were $44.6 million and $52.8 million for the three months ended March 31, 2017 and 2016, respectively. Consolidated SCE&G’s total sales to this affiliate were $44.4 million and $52.5 million for the three months ended March 31, 2017 and 2016, respectively. The net of the total purchases and total sales are recorded in Other expenses on the condensed consolidated statements of income (for the Company) and of comprehensive income (for Consolidated SCE&G). Consolidated SCE&G’s receivable from this affiliate was $13.5 million at March 31, 2017 and $16.0 million at December 31, 2016.  Consolidated SCE&G’s payable to this affiliate was $13.6 million at March 31, 2017 and $16.1 million at December 31, 2016.

Consolidated SCE&G:

SCE&G purchases natural gas and related pipeline capacity from SCANA Energy to serve its retail gas customers and certain electric generation requirements.  Such purchases totaled approximately $23.9 million and $22.4 million for the three months ended March 31, 2017 and 2016, respectively.  SCE&G’s payables to SCANA Energy for such purchases were $8.3 million at March 31, 2017 and $8.8 million at December 31, 2016.

SCANA Services, on behalf of itself and its parent company, provides the following services to Consolidated SCE&G, which are rendered at direct or allocated cost: information systems, telecommunications, customer support, marketing and sales, human resources, corporate compliance, purchasing, financial, risk management, public affairs, legal, investor relations, gas supply and capacity management, strategic planning, general administrative, and retirement benefits. In addition, SCANA Services processes and pays invoices for Consolidated SCE&G and is reimbursed. Costs for these services, including amounts capitalized, totaled $72.5 million and $75.6 million for the three months ended March 31, 2017 and 2016, respectively. Amounts expensed are recorded in Other operation and maintenance - nonconsolidated affiliate and Other expenses on the condensed consolidated statements of comprehensive income. Consolidated SCE&G's payables to SCANA Services for these services were $45.8 million at March 31, 2017 and $63.5 million at December 31, 2016.

Consolidated SCE&G's money pool borrowings from an affiliate are described in Note 4. SCE&G's participation in SCANA's noncontributory defined benefit pension plan and unfunded postretirement health care and life insurance programs is described in Note 8.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

3 Months Ended

Mar. 31, 2017

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 $487 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, the retail natural gas marketing business (including those activities of segments described in Note 10) are presented within Operating Income, and all other activities are presented 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, 29% and 40% of PSNC Energy’s natural gas inventory at March 31, 2017 and December 31, 2016, respectively, with a carrying value of $4.2 million and $9.8 million, respectively.  Under the terms of this agreement, PSNC Energy receives storage asset management feesof which 75% are credited to rate payers. This agreement expired on March 31, 2017, and was replaced with a similar agreement that expires on March 31, 2019.

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.

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 analysis of contracts with customers to which the guidance might be applicable, particularly large customer contracts, has begun. In addition, activities of the FASB's Transition Resource Group for Revenue Recognition are being monitored, particularly as they relate to the required treatment under the standard of contributions in aid of construction, alternative revenue programs and the collectibility of revenue of utilities subject to rate regulation.

In July 2015, the FASB issued accounting guidance intended to simplify the measurement of inventory cost by requiring most inventory to be measured at the lower of cost and net realizable value. The Company and Consolidated SCE&G adopted this guidance in the first quarter of 2017 and the adoption of this guidance did not have any impact on their respective financial statements.

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

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

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

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

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

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

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

In October 2016, the FASB issued accounting guidance related to the tax effects of intra-entity asset transfers of assets other than inventory. An entity will be required to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The Company and Consolidated SCE&G adopted this guidance in the first quarter 2017 and it had no impact on their respective financial statements.

In November 2016, the FASB issued accounting guidance related to the presentation of restricted cash on the statement of cash flows. The guidance is effective for years beginning in 2018, and the Company and Consolidated SCE&G do not anticipate that its adoption will impact their respective financial statements.

In January 2017, the FASB issued accounting guidance to simplify the accounting for goodwill impairment. The guidance removes Step 2 of the goodwill impairment test. The guidance is effective for years beginning in 2020, though early adoption after January 1, 2017 is allowed. The Company and Consolidated SCE&G have not determined when this guidance will be adopted but do not anticipate that its adoption will have a material impact on their respective financial statements.

In March 2017, the FASB issued accounting guidance to change the required presentation of net periodic pension and postretirement benefit cost. Under the new guidance, the net periodic pension and postretirement benefit cost are to be separated into their service cost components and other components. The service cost components are to be presented in the same line item (or items) as other compensation costs arising from services rendered by employees during the period. The other components are to be reported in the income statement separately from the service cost component and outside operating income. Only the service cost component is eligible for capitalization in assets. This guidance is required to be applied on a retrospective basis for the presentation of the service cost component and the other components of net benefit cost and on a prospective basis for the capitalization of only the service cost component of net benefit cost. The Company and Consolidated SCE&G will adopt the guidance when required in the first quarter of 2018 and have not determined what impact it will have on their respective financial statements.

SCEG

Significant Accounting Policies

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

Basis of Consolidation and Variable Interest Entities

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

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

GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $487 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, the retail natural gas marketing business (including those activities of segments described in Note 10) are presented within Operating Income, and all other activities are presented 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 analysis of contracts with customers to which the guidance might be applicable, particularly large customer contracts, has begun. In addition, activities of the FASB's Transition Resource Group for Revenue Recognition are being monitored, particularly as they relate to the required treatment under the standard of contributions in aid of construction, alternative revenue programs and the collectibility of revenue of utilities subject to rate regulation.

In July 2015, the FASB issued accounting guidance intended to simplify the measurement of inventory cost by requiring most inventory to be measured at the lower of cost and net realizable value. The Company and Consolidated SCE&G adopted this guidance in the first quarter of 2017 and the adoption of this guidance did not have any impact on their respective financial statements.

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

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

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

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

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

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

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

In October 2016, the FASB issued accounting guidance related to the tax effects of intra-entity asset transfers of assets other than inventory. An entity will be required to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The Company and Consolidated SCE&G adopted this guidance in the first quarter 2017 and it had no impact on their respective financial statements.

In November 2016, the FASB issued accounting guidance related to the presentation of restricted cash on the statement of cash flows. The guidance is effective for years beginning in 2018, and the Company and Consolidated SCE&G do not anticipate that its adoption will impact their respective financial statements.

In January 2017, the FASB issued accounting guidance to simplify the accounting for goodwill impairment. The guidance removes Step 2 of the goodwill impairment test. The guidance is effective for years beginning in 2020, though early adoption after January 1, 2017 is allowed. The Company and Consolidated SCE&G have not determined when this guidance will be adopted but do not anticipate that its adoption will have a material impact on their respective financial statements.

In March 2017, the FASB issued accounting guidance to change the required presentation of net periodic pension and postretirement benefit cost. Under the new guidance, the net periodic pension and postretirement benefit cost are to be separated into their service cost components and other components. The service cost components are to be presented in the same line item (or items) as other compensation costs arising from services rendered by employees during the period. The other components are to be reported in the income statement separately from the service cost component and outside operating income. Only the service cost component is eligible for capitalization in assets. This guidance is required to be applied on a retrospective basis for the presentation of the service cost component and the other components of net benefit cost and on a prospective basis for the capitalization of only the service cost component of net benefit cost. The Company and Consolidated SCE&G will adopt the guidance when required in the first quarter of 2018 and have not determined what impact it will have on their respective financial statements.

XML

RATE AND OTHER REGULATORY MATTERS (Tables)

3 Months Ended

Mar. 31, 2017

Regulatory Assets

Schedule of Regulatory Assets [Table Text Block]

.

	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2017		December 31, 2016		March 31, 2017		December 31, 2016
Regulatory Assets:
Accumulated deferred income taxes	$	317	$	316	$	309	$	307
AROs and related funding	425		425		402		403
Deferred employee benefit plan costs	336		342		303		309
Deferred losses on interest rate derivatives	614		620		614		620
Unrecovered plant	113		117		113		117
DSM Programs	59		59		59		59
Carrying costs on deferred tax assets related to nuclear construction	37		32		37		32
Pipeline integrity management costs	37		33		6		6
Environmental remediation costs	31		32		25		26
Deferred storm damage costs	20		20		20		20
Deferred costs related to uncertain tax position	17		15		17		15
Other	122		119		121		116
Total Regulatory Assets	$	2,128	$	2,130	$	2,026	$	2,030

Schedule of Regulatory Liabilities [Table Text Block]

Regulatory Liabilities:
Asset removal costs	$	760	$	755	$	533	$	529
Deferred gains on interest rate derivatives	157		151		157		151
Other	21		24		15		15
Total Regulatory Liabilities	$	938	$	930	$	705	$	695

SCEG

Regulatory Assets

Schedule of Regulatory Assets [Table Text Block]

	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2017		December 31, 2016		March 31, 2017		December 31, 2016
Regulatory Assets:
Accumulated deferred income taxes	$	317	$	316	$	309	$	307
AROs and related funding	425		425		402		403
Deferred employee benefit plan costs	336		342		303		309
Deferred losses on interest rate derivatives	614		620		614		620
Unrecovered plant	113		117		113		117
DSM Programs	59		59		59		59
Carrying costs on deferred tax assets related to nuclear construction	37		32		37		32
Pipeline integrity management costs	37		33		6		6
Environmental remediation costs	31		32		25		26
Deferred storm damage costs	20		20		20		20
Deferred costs related to uncertain tax position	17		15		17		15
Other	122		119		121		116
Total Regulatory Assets	$	2,128	$	2,130	$	2,026	$	2,030

Schedule of Regulatory Liabilities [Table Text Block]

Regulatory Liabilities:
Asset removal costs	$	760	$	755	$	533	$	529
Deferred gains on interest rate derivatives	157		151		157		151
Other	21		24		15		15
Total Regulatory Liabilities	$	938	$	930	$	705	$	695

XML

LONG-TERM AND SHORT-TERM DEBT (Tables)

3 Months Ended

Mar. 31, 2017

Short-term Debt [Line Items]

Schedule of Line of Credit Facilities [Table Text Block]

	March 31, 2017
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)	869.5		50.4			769.9			49.2
Weighted average interest rate			1.47		%	1.22		%	1.27		%
Letters of credit supported by LOC	3.3		3.0			0.3			—
Available	$	1,127.2	$	346.6		$	629.8		$	150.8

	December 31, 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)	940.5		64.4			804.3			71.8
Weighted average interest rate			1.43		%	1.04		%	1.07		%
Letters of credit supported by LOC	3.3		3.0			0.3			—
Available	$	1,056.2	$	332.6		$	595.4		$	128.2

SCEG

Short-term Debt [Line Items]

Schedule of Line of Credit Facilities [Table Text Block]

	March 31, 2017
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)	869.5		50.4			769.9			49.2
Weighted average interest rate			1.47		%	1.22		%	1.27		%
Letters of credit supported by LOC	3.3		3.0			0.3			—
Available	$	1,127.2	$	346.6		$	629.8		$	150.8

	December 31, 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)	940.5		64.4			804.3			71.8
Weighted average interest rate			1.43		%	1.04		%	1.07		%
Letters of credit supported by LOC	3.3		3.0			0.3			—
Available	$	1,056.2	$	332.6		$	595.4		$	128.2

XML

DERIVATIVE FINANCIAL INSTRUMENTS (Tables)

3 Months Ended

Mar. 31, 2017

Derivative [Line Items]

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

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

	Commodity and Other Energy Management Contracts (in MMBTU)
Hedge designation	Gas Distribution	Gas Marketing	Total
As of March 31, 2017
Commodity contracts	6,500,000	10,134,000	16,634,000
Energy management contracts (a)	—	55,028,797	55,028,797
Total (a)	6,500,000	65,162,797	71,662,797
As of December 31, 2016
Commodity contracts	4,510,000	11,947,000	16,457,000
Energy management contracts (a)	—	67,447,223	67,447,223
Total (a)	4,510,000	79,394,223	83,904,223

(a)  Includes amounts related to basis swap contracts totaling 9,630,864 MMBTU in 2017 and 730,721 MMBTU in 2016.

Schedule of Derivative Instruments [Table Text Block]

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

Interest Rate Swaps
	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2017		December 31, 2016		March 31, 2017		December 31, 2016
Designated as hedging instruments	$	115.6	$	115.6	$	36.4	$	36.4
Not designated as hedging instruments	1,285.0		1,285.0		1,285.0		1,285.0

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

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

Fair Values of Derivative Instruments
		The Company				Consolidated SCE&G
Millions of dollars	Balance Sheet Location	Asset		Liability		Asset		Liability
As of March 31, 2017
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments	—		$	2	—		$	1
	Other deferred credits and other liabilities	—		25		—		8
Commodity contracts
	Prepayments	$	1	—		—		—
	Other current assets	1		—		—		—
Total		$	2	$	27	—		$	9
Not designated as hedging instruments
Interest rate contracts
	Other deferred debits and other assets	$	77	—		$	77	—
	Derivative financial instruments	—		$	22	—		$	22
	Other deferred credits and other liabilities	—		3		—		3
Commodity contracts
	Prepayments	2		—		—		—
Energy management contracts
	Prepayments	2		1		—		—
	Other current assets	2		—		—		—
	Other deferred debits and other assets	1		—		—		—
	Derivative financial instruments	—		3		—		—
	Other deferred credits and other liabilities	—		1		—		—
Total		$	84	$	30	$	77	$	25
As of December 31, 2016
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments	—		$	4	—		$	1
	Other deferred credits and other liabilities	—		24		—		8
Commodity contracts
	Prepayments	$	5	—		—		—
	Other current assets	1		—		—		—
Total		$	6	$	28	—		$	9
Not designated as hedging instruments
Interest rate contracts
	Other deferred debits and other assets	$	71	—		$	71	—
	Derivative financial instruments	—		$	27	—		$	27
	Other deferred credits and other liabilities	—		3		—		3
Commodity contracts
	Other current assets	3		—		—		—
Energy management contracts
	Prepayments	6		2		—		—
	Other current assets	2		1		—		—
	Other deferred debits and other assets	2		—		—		—
	Derivative financial instruments	—		4		—		—
	Other deferred credits and other liabilities	—		2		—		—
Total		$	84	$	39	$	71	$	30

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
Millions of dollars	2017	2016			Location	2017			2016
Three Months Ended March 31,
Interest rate contracts	—	$	(3	)	Interest expense	$	(1	)	$	(1	)

The Company:
	Loss Recognized in OCI, net of tax							Gain/(Loss) Reclassified from AOCI into Income, net of tax
Millions of dollars	2017			2016			Location	2017			2016
Three Months Ended March 31,
Interest rate contracts	—			$	(3	)	Interest expense	$	(2	)	$	(2	)
Commodity contracts	$	(2	)	(2		)	Gas purchased for resale	2			(5		)
Total	$	(2	)	$	(5	)		$	—		$	(7	)

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:
	Gain (Loss) Deferred in Regulatory Accounts						Loss Reclassified from Deferred Accounts into Income
Millions of dollars	2017		2016			Location	2017			2016
Three Months Ended March 31,
Interest rate contracts	$	11	$	(144	)	Interest Expense	$	(1	)	—

Disclosure of Credit Derivatives [Table Text Block]

Derivative Contracts with Credit Contingent Features
	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2017		December 31, 2016		March 31, 2017		December 31, 2016
in Net Liability Position
Aggregate fair value of derivatives in net liability position	$	46.0	$	50.3	$	26.4	$	30.3
Fair value of collateral already posted	30.4		29.2		9.0		9.2
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	$	15.6	$	21.1	$	17.4	$	21.1
in Net Asset Position
Aggregate fair value of derivatives in net asset position	$	69.9	$	62.9	$	69.6	$	62.0
Fair value of collateral already posted	—		—		—		—
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	$	69.9	$	62.9	$	69.6	$	62.0

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 March 31, 2017
Gross Amounts of Recognized Assets	$	77		$	4	$	5		$	86		$	77
Gross Amounts Offset in Statement of Financial Position	—			—		(1		)	(1		)	—
Net Amounts Presented in Statement of Financial Position	77			4		4			85			77
Gross Amounts Not Offset - Financial Instruments	(8		)	—		—			(8		)	(8		)
Gross Amounts Not Offset - Cash Collateral Received	—			—		—			—			—
Net Amount	$	69		$	4	$	4		$	77		$	69
Balance sheet location
Prepayments									$	4		—
Other current assets									2			—
Other deferred debits and other assets									79			$	77
Total									$	85		$	77
As of December 31, 2016
Gross Amounts of Recognized Assets	$	71		$	9	$	10		$	90		$	71
Gross Amounts Offset in Statement of Financial Position	—			—		(4		)	(4		)	—
Net Amounts Presented in Statement of Financial Position	71			9		6			86			71
Gross Amounts Not Offset - Financial Instruments	(9		)	—		—			(9		)	(9		)
Gross Amounts Not Offset - Cash Collateral Received	—			—		—			—			—
Net Amount	$	62		$	9	$	6		$	77		$	62
Balance sheet location
Prepayments									$	9		—
Other current assets									5			—
Other deferred debits and other assets									72			$	71
Total									$	86		$	71

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 March 31, 2017
Gross Amounts of Recognized Liabilities	$	52		—	$	5		$	57		$	34
Gross Amounts Offset in Statement of Financial Position	—			—	(1		)	(1		)	—
Net Amounts Presented in Statement of Financial Position	52			—	4			56			34
Gross Amounts Not Offset - Financial Instruments	(8		)	—	—			(8		)	(8		)
Gross Amounts Not Offset - Cash Collateral Posted	(29		)	—	(1		)	(30		)	(9		)
Net Amount	$	15		—	$	3		$	18		$	17
Balance sheet location
Derivative financial instruments								$	27		$	23
Other deferred credits and other liabilities								29			11
Total								$	56		$	34
As of December 31, 2016
Gross Amounts of Recognized Liabilities	$	58		—	$	9		$	67		$	39
Gross Amounts Offset in Statement of Financial Position	—			—	(3		)	(3		)	—
Net Amounts Presented in Statement of Financial Position	58			—	6			64			39
Gross Amounts Not Offset - Financial Instruments	(9		)	—	—			(9		)	(9		)
Gross Amounts Not Offset - Cash Collateral Posted	(29		)	—	—			(29		)	(9		)
Net Amount	$	20		—	$	6		$	26		$	21
Balance sheet location
Derivative financial instruments								$	35		$	28
Other deferred credits and other liabilities								29			11
Total								$	64		$	39

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	March 31, 2017		December 31, 2016		March 31, 2017		December 31, 2016
Designated as hedging instruments	$	115.6	$	115.6	$	36.4	$	36.4
Not designated as hedging instruments	1,285.0		1,285.0		1,285.0		1,285.0

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

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

Fair Values of Derivative Instruments
		The Company				Consolidated SCE&G
Millions of dollars	Balance Sheet Location	Asset		Liability		Asset		Liability
As of March 31, 2017
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments	—		$	2	—		$	1
	Other deferred credits and other liabilities	—		25		—		8
Commodity contracts
	Prepayments	$	1	—		—		—
	Other current assets	1		—		—		—
Total		$	2	$	27	—		$	9
Not designated as hedging instruments
Interest rate contracts
	Other deferred debits and other assets	$	77	—		$	77	—
	Derivative financial instruments	—		$	22	—		$	22
	Other deferred credits and other liabilities	—		3		—		3
Commodity contracts
	Prepayments	2		—		—		—
Energy management contracts
	Prepayments	2		1		—		—
	Other current assets	2		—		—		—
	Other deferred debits and other assets	1		—		—		—
	Derivative financial instruments	—		3		—		—
	Other deferred credits and other liabilities	—		1		—		—
Total		$	84	$	30	$	77	$	25
As of December 31, 2016
Designated as hedging instruments
Interest rate contracts
	Derivative financial instruments	—		$	4	—		$	1
	Other deferred credits and other liabilities	—		24		—		8
Commodity contracts
	Prepayments	$	5	—		—		—
	Other current assets	1		—		—		—
Total		$	6	$	28	—		$	9
Not designated as hedging instruments
Interest rate contracts
	Other deferred debits and other assets	$	71	—		$	71	—
	Derivative financial instruments	—		$	27	—		$	27
	Other deferred credits and other liabilities	—		3		—		3
Commodity contracts
	Other current assets	3		—		—		—
Energy management contracts
	Prepayments	6		2		—		—
	Other current assets	2		1		—		—
	Other deferred debits and other assets	2		—		—		—
	Derivative financial instruments	—		4		—		—
	Other deferred credits and other liabilities	—		2		—		—
Total		$	84	$	39	$	71	$	30

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
Millions of dollars	2017	2016			Location	2017			2016
Three Months Ended March 31,
Interest rate contracts	—	$	(3	)	Interest expense	$	(1	)	$	(1	)

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

Derivatives Not designated as Hedging Instruments
The Company and Consolidated SCE&G:
	Gain (Loss) Deferred in Regulatory Accounts						Loss Reclassified from Deferred Accounts into Income
Millions of dollars	2017		2016			Location	2017			2016
Three Months Ended March 31,
Interest rate contracts	$	11	$	(144	)	Interest Expense	$	(1	)	—

Disclosure of Credit Derivatives [Table Text Block]

Derivative Contracts with Credit Contingent Features
	The Company				Consolidated SCE&G
Millions of dollars	March 31, 2017		December 31, 2016		March 31, 2017		December 31, 2016
in Net Liability Position
Aggregate fair value of derivatives in net liability position	$	46.0	$	50.3	$	26.4	$	30.3
Fair value of collateral already posted	30.4		29.2		9.0		9.2
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	$	15.6	$	21.1	$	17.4	$	21.1
in Net Asset Position
Aggregate fair value of derivatives in net asset position	$	69.9	$	62.9	$	69.6	$	62.0
Fair value of collateral already posted	—		—		—		—
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	$	69.9	$	62.9	$	69.6	$	62.0

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 March 31, 2017
Gross Amounts of Recognized Assets	$	77		$	4	$	5		$	86		$	77
Gross Amounts Offset in Statement of Financial Position	—			—		(1		)	(1		)	—
Net Amounts Presented in Statement of Financial Position	77			4		4			85			77
Gross Amounts Not Offset - Financial Instruments	(8		)	—		—			(8		)	(8		)
Gross Amounts Not Offset - Cash Collateral Received	—			—		—			—			—
Net Amount	$	69		$	4	$	4		$	77		$	69
Balance sheet location
Prepayments									$	4		—
Other current assets									2			—
Other deferred debits and other assets									79			$	77
Total									$	85		$	77
As of December 31, 2016
Gross Amounts of Recognized Assets	$	71		$	9	$	10		$	90		$	71
Gross Amounts Offset in Statement of Financial Position	—			—		(4		)	(4		)	—
Net Amounts Presented in Statement of Financial Position	71			9		6			86			71
Gross Amounts Not Offset - Financial Instruments	(9		)	—		—			(9		)	(9		)
Gross Amounts Not Offset - Cash Collateral Received	—			—		—			—			—
Net Amount	$	62		$	9	$	6		$	77		$	62
Balance sheet location
Prepayments									$	9		—
Other current assets									5			—
Other deferred debits and other assets									72			$	71
Total									$	86		$	71

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 March 31, 2017
Gross Amounts of Recognized Liabilities	$	52		—	$	5		$	57		$	34
Gross Amounts Offset in Statement of Financial Position	—			—	(1		)	(1		)	—
Net Amounts Presented in Statement of Financial Position	52			—	4			56			34
Gross Amounts Not Offset - Financial Instruments	(8		)	—	—			(8		)	(8		)
Gross Amounts Not Offset - Cash Collateral Posted	(29		)	—	(1		)	(30		)	(9		)
Net Amount	$	15		—	$	3		$	18		$	17
Balance sheet location
Derivative financial instruments								$	27		$	23
Other deferred credits and other liabilities								29			11
Total								$	56		$	34
As of December 31, 2016
Gross Amounts of Recognized Liabilities	$	58		—	$	9		$	67		$	39
Gross Amounts Offset in Statement of Financial Position	—			—	(3		)	(3		)	—
Net Amounts Presented in Statement of Financial Position	58			—	6			64			39
Gross Amounts Not Offset - Financial Instruments	(9		)	—	—			(9		)	(9		)
Gross Amounts Not Offset - Cash Collateral Posted	(29		)	—	—			(29		)	(9		)
Net Amount	$	20		—	$	6		$	26		$	21
Balance sheet location
Derivative financial instruments								$	35		$	28
Other deferred credits and other liabilities								29			11
Total								$	64		$	39

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Tables)

3 Months Ended

Mar. 31, 2017

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

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

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

	As of March 31, 2017						As of December 31, 2016
	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	$	15	—		—		$	14	—		—
Held to maturity securities	—		$	7	—		—		$	7	—
Interest rate contracts	—		77		$	77	—		71		$	71
Commodity contracts	3		1		—		8		1		—
Energy management contracts	2		3		—		6		4		—
Liabilities:
Interest rate contracts	—		52		34		—		58		39
Energy management contracts	—		8		—		2		10		—

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

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

Long-Term Debt	March 31, 2017				December 31, 2016
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
The Company	$	6,482.7	$	7,029.0	$	6,489.8	$	7,183.3
Consolidated SCE&G	5,158.7		5,606.6		5,166.0		5,752.3

SCEG [member]

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

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

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

	As of March 31, 2017						As of December 31, 2016
	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	$	15	—		—		$	14	—		—
Held to maturity securities	—		$	7	—		—		$	7	—
Interest rate contracts	—		77		$	77	—		71		$	71
Commodity contracts	3		1		—		8		1		—
Energy management contracts	2		3		—		6		4		—
Liabilities:
Interest rate contracts	—		52		34		—		58		39
Energy management contracts	—		8		—		2		10		—

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

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

Long-Term Debt	March 31, 2017				December 31, 2016
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
The Company	$	6,482.7	$	7,029.0	$	6,489.8	$	7,183.3
Consolidated SCE&G	5,158.7		5,606.6		5,166.0		5,752.3

XML

EMPLOYEE BENEFIT PLANS (Tables)

3 Months Ended

Mar. 31, 2017

Pension and Other Postretirement Benefit Plans

Schedule of Net Benefit Costs [Table Text Block]

The Company	Pension Benefits						Other Postretirement Benefits
	2017			2016			2017		2016
Three months ended March 31,
Service cost	$	5.3		$	5.5		$	1.2	$	1.3
Interest cost	9.4			9.9			2.9		3.0
Expected return on assets	(13.8		)	(14.1		)	—		—
Prior service cost amortization	0.4			1.0			—		0.1
Amortization of actuarial losses	3.9			3.7			0.4		0.1
Net periodic benefit cost	$	5.2		$	6.0		$	4.5	$	4.5

Consolidated SCE&G	Pension Benefits						Other Postretirement Benefits
	2017			2016			2017		2016
Three months ended March 31,
Service cost	$	4.4		$	4.5		$	1.0	$	1.0
Interest cost	8.1			8.4			2.4		2.5
Expected return on assets	(11.8		)	(11.9		)	—		—
Prior service cost amortization	0.3			0.8			—		0.1
Amortization of actuarial losses	3.4			3.1			0.3		0.1
Net periodic benefit cost	$	4.4		$	4.9		$	3.7	$	3.7

SCEG

Pension and Other Postretirement Benefit Plans

Schedule of Net Benefit Costs [Table Text Block]

Consolidated SCE&G	Pension Benefits						Other Postretirement Benefits
	2017			2016			2017		2016
Three months ended March 31,
Service cost	$	4.4		$	4.5		$	1.0	$	1.0
Interest cost	8.1			8.4			2.4		2.5
Expected return on assets	(11.8		)	(11.9		)	—		—
Prior service cost amortization	0.3			0.8			—		0.1
Amortization of actuarial losses	3.4			3.1			0.3		0.1
Net periodic benefit cost	$	4.4		$	4.9		$	3.7	$	3.7

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SEGMENT OF BUSINESS INFORMATION (Tables)

3 Months Ended

Mar. 31, 2017

Segment Reporting Information [Line Items]

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

The Company
Millions of dollars	External Revenue		Intersegment Revenue			Operating Income		Net Income
Three Months Ended March 31, 2017
Electric Operations	$	577	$	1		$	178	n/a
Gas Distribution	322		—			113		n/a
Gas Marketing	274		24			n/a		$	15
All Other	—		94			—		—
Adjustments/Eliminations	—		(119		)	25		156
Consolidated Total	$	1,173	$	—		$	316	$	171

Three Months Ended March 31, 2016
Electric Operations	$	592	$	1		$	198	n/a
Gas Distribution	299		1			94		n/a
Gas Marketing	281		22			n/a		$	24
All Other	—		98			—		—
Adjustments/Eliminations	—		(122		)	39		152
Consolidated Total	$	1,172	$	—		$	331	$	176

Consolidated SCE&G
Millions of dollars	External Revenue		Operating Income		Earnings Available to Common Shareholder
Three Months Ended March 31, 2017
Electric Operations	$	578	$	178	n/a
Gas Distribution	141		44		n/a
Adjustments/Eliminations	—		—		$	109
Consolidated Total	$	719	$	222	$	109

Three Months Ended March 31, 2016
Electric Operations	$	593	$	198	n/a
Gas Distribution	124		38		n/a
Adjustments/Eliminations	—		—		$	113
Consolidated Total	$	717	$	236	$	113

Segment Assets	The Company				Consolidated SCE&G
	March 31,		December 31,		March 31,		December 31,
Millions of dollars	2017		2016		2017		2016
Electric Operations	$	12,076	$	11,929	$	12,076	$	11,929
Gas Distribution	2,926		2,892		836		825
Gas Marketing	202		230		n/a		n/a
All Other	997		1,124		n/a		n/a
Adjustments/Eliminations	2,257		2,532		3,053		3,337
Consolidated Total	$	18,458	$	18,707	$	15,965	$	16,091

SCEG

Segment Reporting Information [Line Items]

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

Consolidated SCE&G
Millions of dollars	External Revenue		Operating Income		Earnings Available to Common Shareholder
Three Months Ended March 31, 2017
Electric Operations	$	578	$	178	n/a
Gas Distribution	141		44		n/a
Adjustments/Eliminations	—		—		$	109
Consolidated Total	$	719	$	222	$	109

Three Months Ended March 31, 2016
Electric Operations	$	593	$	198	n/a
Gas Distribution	124		38		n/a
Adjustments/Eliminations	—		—		$	113
Consolidated Total	$	717	$	236	$	113

Segment Assets	The Company				Consolidated SCE&G
	March 31,		December 31,		March 31,		December 31,
Millions of dollars	2017		2016		2017		2016
Electric Operations	$	12,076	$	11,929	$	12,076	$	11,929
Gas Distribution	2,926		2,892		836		825
Gas Marketing	202		230		n/a		n/a
All Other	997		1,124		n/a		n/a
Adjustments/Eliminations	2,257		2,532		3,053		3,337
Consolidated Total	$	18,458	$	18,707	$	15,965	$	16,091

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) $ in Millions	3 Months Ended
	Mar. 31, 2017 USD ($) MW	Dec. 31, 2016 USD ($)
Significant Accounting Policies
Property, Plant and Equipment, Net	$ 275.0	$ 276.0
SCEG
Significant Accounting Policies
Property, Plant and Equipment, Net	$ 69.0	$ 69.0
Genco
Significant Accounting Policies
Power Generation Capacity Megawatts | MW	605
Property, Plant and Equipment, Net	$ 487.0
PSNC Energy [Member]
Significant Accounting Policies
Percentage of natural gas inventory held by counterparties under asset management and supply service agreements (as a percent)	29.00%	40.00%
Natural gas inventory, carrying amount	$ 4.2	$ 9.8
PercentOfStorageFeesCreditedToRatePayers	75.00%

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RATE AND OTHER REGULATORY MATTERS (Details) $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2017 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2013
SCEG
Rate Matters [Line Items]
Capacity of renewable energy facilities by 2020	84.5
SCPSC Order, Recovery Of Projected DER Program Costs	$ 16.5
SCPSC Order for Increase of Total Fuel Cost Component of Retail Electric Rates to produce a projected under recovery	61.0
SCPSC Order, Approx Annual pension rider decrease amount	11.9
Carrying costs on deferred income tax assets	4.3	$ 3.1
SCPSC Order, Annual DSM Program Rate Rider Recovery Amount	37.0
PSNC Energy
Rate Matters [Line Items]
Pipeline integrity mgmt annual revenue requirement approved by NCUC	$ 1.9
Deferred Income Tax Charges [Member]
Rate Matters [Line Items]
Regulatory Noncurrent Asset Amortization Period	85 years
Asset Retirement Obligation Costs [Member]
Rate Matters [Line Items]
Regulatory Noncurrent Asset Amortization Period	110 years
Environmental Restoration Costs [Member]
Rate Matters [Line Items]
MPG environmental remediation	18
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
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
Pension Costs [Member] | SCEG
Rate Matters [Line Items]
Regulatory Noncurrent Asset Amortization Period	11 years

XML

RATE AND OTHER REGULATORY MATTERS (Details 2) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 2013	Dec. 31, 2016
Regulatory Assets
Regulatory Assets, Noncurrent	$ 2,128.0		$ 2,130.0
SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	2,026.0		2,030.0
PSNC Energy [Member]
Regulatory Assets
Pipeline integrity management costs, amount deferred pending future approval of rate recovery	11.3
Pipeline integrity management costs, amount recovering beginning November 2016	$ 20.3
Deferred Income Tax Charges [Member]
Regulatory Assets
Regulatory Asset, Amortization Period	85 years
Regulatory Assets, Noncurrent	$ 317.0		316.0
Deferred Income Tax Charges [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	$ 309.0		307.0
Asset Retirement Obligation Costs [Member]
Regulatory Assets
Regulatory Asset, Amortization Period	110 years
Regulatory Assets, Noncurrent	$ 425.0		425.0
Asset Retirement Obligation Costs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	402.0		403.0
Pension Costs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	$ 336.0		342.0
Pension Costs [Member] | SCEG
Regulatory Assets
Regulatory Asset, Amortization Period	11 years
Regulatory Assets, Noncurrent	$ 303.0		309.0
Pension costs, electric [Member] | SCEG
Regulatory Assets
Regulatory Asset, Amortization Period		30 years
Deferred Losses On Interest Rate Derivatives [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	614.0		620.0
Deferred Losses On Interest Rate Derivatives [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	614.0		620.0
unrecovered plant [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	113.0		117.0
unrecovered plant [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	113.0		117.0
Demand Side Management programs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	$ 59.0		59.0
Demand Side Management programs [Member] | SCEG
Regulatory Assets
Regulatory Asset, Amortization Period	5 years
Regulatory Assets, Noncurrent	$ 59.0		59.0
carrying cost on nuclear [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	$ 37.0		32.0
carrying cost on nuclear [Member] | SCEG
Regulatory Assets
Regulatory Asset, Amortization Period	10 years
Regulatory Assets, Noncurrent	$ 37.0		32.0
Pipeline integrity management costs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	37.0		33.0
Pipeline integrity management costs [Member] | SCEG
Regulatory Assets
Pipeline integrity management costs, annual amortization amount	1.9
Regulatory Assets, Noncurrent	$ 6.0		6.0
Pipeline integrity management costs [Member] | PSNC Energy [Member]
Regulatory Assets
Regulatory Asset, Amortization Period	5 years
Environmental Restoration Costs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	$ 31.0		32.0
Environmental Restoration Costs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	25.0		26.0
Storm Costs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	20.0		20.0
Storm Costs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	20.0		20.0
Deferred costs uncertain tax position [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	17.0		15.0
Deferred costs uncertain tax position [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	17.0		15.0
Other Regulatory Assets [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	122.0		119.0
Other Regulatory Assets [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	$ 121.0		$ 116.0

XML

RATE AND OTHER REGULATORY MATTERS (Details 3) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Regulatory Liabilities [Line Items]
Regulatory Assets, Noncurrent	$ 2,128	$ 2,130
Regulatory Liabilities	938	930
SCEG
Regulatory Liabilities [Line Items]
Regulatory Assets, Noncurrent	2,026	2,030
Regulatory Liabilities	705	695
Asset Retirement Obligation Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	760	755
Asset Retirement Obligation Costs [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	533	529
Deferred gains on interest rate derivatives [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	157	151
Deferred gains on interest rate derivatives [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	157	151
Other Regulatory Liability [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	21	24
Other Regulatory Liability [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 15	$ 15

XML

COMMON EQUITY (Details) - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Schedule of Capitalization, Equity [Line Items]
Common Stock, Shares Authorized	200.0		200.0
Common Stock, Shares, Outstanding	142.9		142.9
SCEG
Schedule of Capitalization, Equity [Line Items]
Common Stock, Shares Authorized	50.0		50.0
Common Stock, Shares, Outstanding	40.3		40.3
Preferred Stock, Shares Authorized	20.0		20.0
Preferred Stock, Shares Outstanding	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	$ 2	$ (5)
Interest Rate Contract [Member]
Schedule of Capitalization, Equity [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(2)	(2)
Gas Purchased for Resale [Member] [Member] | Cash Flow Hedging [Member] | Commodity Contract
Schedule of Capitalization, Equity [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(2)	5
Interest Expense [Member] | Cash Flow Hedging [Member] | Interest Rate Contract [Member]
Schedule of Capitalization, Equity [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 2	$ 2

XML

LONG-TERM AND SHORT-TERM DEBT (Details) - SCEG - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 67.8	$ 67.8
Related Party Transaction, Due from (to) Related Party, Current	$ 28.0	$ 29.0

XML

LONG-TERM AND SHORT-TERM DEBT (Details 2) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 2,000.0	$ 2,000.0
Commercial Paper	869.5	940.5
Letters of Credit Outstanding, Amount	3.3	3.3
Line of Credit Facility, Remaining Borrowing Capacity	1,127.2	1,056.2
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	$ 50.4	$ 64.4
Debt, Weighted Average Interest Rate	1.47%	1.43%
Letters of Credit Outstanding, Amount	$ 3.0	$ 3.0
Line of Credit Facility, Remaining Borrowing Capacity	346.6	332.6
SCEG including Fuel Company [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	1,400.0	1,400.0
Commercial Paper	$ 769.9	$ 804.3
Debt, Weighted Average Interest Rate	1.22%	1.04%
Letters of Credit Outstanding, Amount	$ 0.3	$ 0.3
Line of Credit Facility, Remaining Borrowing Capacity	629.8	595.4
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	$ 49.2	$ 71.8
Debt, Weighted Average Interest Rate	1.27%	1.07%
Line of Credit Facility, Remaining Borrowing Capacity	$ 150.8	$ 128.2

XML

INCOME TAXES (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	$ 382
Unrecognized Tax Benefits	274	$ 219
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	273
Decrease in Unrecognized Tax Benefits is Reasonably Possible	$ 53
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent	3.00%	4.00%
SCEG
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	$ 382
Unrecognized Tax Benefits	333	$ 236
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	273
Decrease in Unrecognized Tax Benefits is Reasonably Possible	$ 53

XML

DERIVATIVE FINANCIAL INSTRUMENTS (Details)	3 Months Ended	12 Months Ended
	Mar. 31, 2017 USD ($) MMBTU	Dec. 31, 2016 MMBTU
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	71,662,797	83,904,223
Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	6,500,000	4,510,000
Gas Marketing segment [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	65,162,797	79,394,223
Commodity Contract
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	16,634,000	16,457,000
Commodity Contract | Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	6,500,000	4,510,000
Commodity Contract | Gas Marketing segment [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	10,134,000	11,947,000
Energy Related Derivative [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	55,028,797	67,447,223
Energy Related Derivative [Member] | Gas Marketing segment [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	55,028,797	67,447,223
Energy Related Derivative [Member] | Basis Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure	9,630,864	730,721

XML

DERIVATIVE FINANCIAL INSTRUMENTS Fair Value on Balance Sheet (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 86.0	$ 90.0
Derivative Liability, Fair Value, Gross Liability	57.0	67.0
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	77.0	71.0
Derivative Liability, Fair Value, Gross Liability	52.0	58.0
Commodity Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	4.0	9.0
Derivative Liability, Fair Value, Gross Liability		0.0
Other Energy Management Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	5.0	10.0
Derivative Liability, Fair Value, Gross Liability	5.0	9.0
Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	2.0	6.0
Derivative Liability, Fair Value, Gross Liability	27.0	28.0
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	115.6	115.6
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	2.0	4.0
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	25.0	24.0
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Prepayments [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	1.0	5.0
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	1.0	1.0
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	84.0	84.0
Derivative Liability, Fair Value, Gross Liability	30.0	39.0
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	1,285.0	1,285.0
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	22.0	27.0
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	77.0	71.0
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	3.0	3.0
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Prepayments [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	2.0
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset		3.0
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	3.0	4.0
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	1.0	2.0
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	1.0	2.0
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Prepayments [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	2.0	6.0
Derivative Liability, Fair Value, Gross Liability	1.0	2.0
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	2.0	2.0
Derivative Liability, Fair Value, Gross Liability		1.0
SCEG | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	77.0	71.0
Derivative Liability, Fair Value, Gross Liability	34.0	39.0
SCEG | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	9.0	9.0
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	8.0	8.0
SCEG | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	77.0	71.0
Derivative Liability, Fair Value, Gross Liability	25.0	30.0
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	1,285.0	1,285.0
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	22.0	27.0
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	77.0	71.0
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	$ 3.0	$ 3.0

XML

DERIVATIVE FINANCIAL INSTRUMENTS On Income Statement (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Derivative [Line Items]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	$ (2.0)	$ (5.0)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	$ 0.0	$ (7.0)
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant	insignificant
Commodity Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ (2.0)	$ 5.0
Commodity Contract | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	(2.0)	(2.0)
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	2.0	2.0
Interest Rate Contract [Member] | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net		(3.0)
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	11.0	(144.0)
Interest Rate Contract [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net		(3.0)
Other Nonoperating Income (Expense) [Member] | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income		0.0
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	0.6
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	2.0	(5.0)
Interest Expense [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred	6.5
Interest Expense [Member] | Interest Rate Contract [Member] | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(2.0)	(2.0)
Interest Expense [Member] | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	(1.0)
Interest Expense [Member] | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred	2.4
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	1.7
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	$ (1.0)	$ (1.0)
SCEG
Derivative [Line Items]
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant	insignificant
SCEG | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	$ 11.0	$ (144.0)
SCEG | Interest Rate Contract [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net		(3.0)
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)
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	2.4
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	1.7
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	$ (1.0)	$ (1.0)

XML

DERIVATIVE FINANCIAL INSTRUMENTS Derivative Financial Instruments (Credit Risk) (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Letter of Credit Available Commodity Derivatives asset position	$ 1.8	$ 1.5
Commodity Derivative, Net Asset Position, Aggregate Fair Value	6.0	9.0
Collateral Already Posted, Aggregate Fair Value	30.4	29.2
Additional Collateral, Aggregate Fair Value	15.6	21.1
Derivative, Net Liability Position, Aggregate Fair Value	46.0	50.3
Cash collateral to request from interest rate derivative counterparty	69.9	62.9
Interest Rate Derivative, net asset position, Aggregate Fair Value	69.9	62.9
SCEG
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	9.0	9.2
Additional Collateral, Aggregate Fair Value	17.4	21.1
Derivative, Net Liability Position, Aggregate Fair Value	26.4	30.3
Cash collateral to request from interest rate derivative counterparty	69.6	62.0
Interest Rate Derivative, net asset position, Aggregate Fair Value	$ 69.6	$ 62.0

XML

DERIVATIVE FINANCIAL INSTRUMENTS Derivative Financial Instruments Offsetting Assets and Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 86	$ 90
Derivative Asset, Fair Value, Gross Liability	(1)	(4)
Derivative Asset	85	86
Derivative Liability, Fair Value, Gross Liability	57	67
Derivative Liability, Fair Value, Gross Asset	(1)	(3)
Derivative, Collateral, Right to Reclaim Securities	(8)	(9)
Derivative, Collateral, Right to Reclaim Cash	(30)	(29)
Derivative Liability, Fair Value, Amount Offset Against Collateral	18	26
Derivative Liability	56	64
Derivative, Collateral, Obligation to Return Securities	(8)	(9)
Derivative, Collateral, Obligation to Return Cash	0	0
Derivative Asset, Fair Value, Amount Offset Against Collateral	77	77
Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability	27	35
Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	79	72
Prepayments [Member]
Derivative [Line Items]
Derivative Asset	4	9
Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset	2	5
Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability	29	29
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	77	71
Derivative Asset	77	71
Derivative Liability, Fair Value, Gross Liability	52	58
Derivative, Collateral, Right to Reclaim Securities	(8)	(9)
Derivative, Collateral, Right to Reclaim Cash	(29)	(29)
Derivative Liability, Fair Value, Amount Offset Against Collateral	15	20
Derivative Liability	52	58
Derivative, Collateral, Obligation to Return Securities	(8)	(9)
Derivative Asset, Fair Value, Amount Offset Against Collateral	69	62
Commodity Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	4	9
Derivative Asset	4	9
Derivative Liability, Fair Value, Gross Liability		0
Derivative Liability, Fair Value, Amount Offset Against Collateral		0
Derivative Liability		0
Derivative Asset, Fair Value, Amount Offset Against Collateral	4	9
Other Energy Management Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	5	10
Derivative Asset, Fair Value, Gross Liability	(1)	(4)
Derivative Asset	4	6
Derivative Liability, Fair Value, Gross Liability	5	9
Derivative Liability, Fair Value, Gross Asset	(1)	(3)
Derivative, Collateral, Right to Reclaim Cash	(1)
Derivative Liability, Fair Value, Amount Offset Against Collateral	3	6
Derivative Liability	4	6
Derivative Asset, Fair Value, Amount Offset Against Collateral	4	6
SCEG
Derivative [Line Items]
Derivative Asset	77	71
Derivative Liability	34	39
SCEG | Derivative Financial Instruments, Liabilities [Member]
Derivative [Line Items]
Derivative Liability	23	28
SCEG | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	77	71
SCEG | Other Deferred Credits and Other Liabilities [Member]
Derivative [Line Items]
Derivative Liability	11	11
SCEG | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	77	71
Derivative Asset	77	71
Derivative Liability, Fair Value, Gross Liability	34	39
Derivative, Collateral, Right to Reclaim Securities	(8)	(9)
Derivative, Collateral, Right to Reclaim Cash	(9)	(9)
Derivative Liability, Fair Value, Amount Offset Against Collateral	17	21
Derivative Liability	34	39
Derivative, Collateral, Obligation to Return Securities	(8)	(9)
Derivative Asset, Fair Value, Amount Offset Against Collateral	$ 69	$ 62

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
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	$ 15	$ 14
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	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	77	71
Liabilities, Fair Value Disclosure	52	58
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	3	8
Commodity Contract | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure	1	1
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	2	6
Liabilities, Fair Value Disclosure		2
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	3	4
Liabilities, Fair Value Disclosure	8	10
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	77	71
Liabilities, Fair Value Disclosure	$ 34	$ 39

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details 2) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	$ 6,482.7	$ 6,489.8
Long-term Debt, Fair Value	7,029.0	7,183.3
SCEG
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	5,158.7	5,166.0
Long-term Debt, Fair Value	$ 5,606.6	$ 5,752.3

XML

EMPLOYEE BENEFIT PLANS (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Pension and Other Postretirement Benefit Plans
Pension Contributions	No
Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	$ 5.3	$ 5.5
Interest cost	9.4	9.9
Expected return on assets	(13.8)	(14.1)
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	0.4	1.0
Defined Benefit Plan, Actuarial Net (Gains) Losses	3.9	3.7
Defined Benefit Plan, Net Periodic Benefit Cost	5.2	6.0
Other Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	1.2	1.3
Interest cost	2.9	3.0
Expected return on assets	0.0	0.0
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	0.0	0.1
Defined Benefit Plan, Actuarial Net (Gains) Losses	0.4	0.1
Defined Benefit Plan, Net Periodic Benefit Cost	$ 4.5	4.5
SCEG
Pension and Other Postretirement Benefit Plans
Pension Contributions	No
SCEG | Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	$ 4.4	4.5
Interest cost	8.1	8.4
Expected return on assets	(11.8)	(11.9)
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	0.3	0.8
Defined Benefit Plan, Actuarial Net (Gains) Losses	3.4	3.1
Defined Benefit Plan, Net Periodic Benefit Cost	4.4	4.9
SCEG | Other Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	1.0	1.0
Interest cost	2.4	2.5
Expected return on assets	0.0	0.0
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	0.0	0.1
Defined Benefit Plan, Actuarial Net (Gains) Losses	0.3	0.1
Defined Benefit Plan, Net Periodic Benefit Cost	$ 3.7	$ 3.7

XML

COMMITMENTS AND CONTINGENCIES (Details) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2017 USD ($)	Dec. 31, 2017	Dec. 31, 2016	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%
Time frame for CPP cases held in abeyance by Court of Appeals	60
NPDES permit renewal permit period	five
Nuclear Generation
Toshiba impairment loss for the nine months ended 12/31/16 for fiscal year ended 3/31/17	$ 6,200.0
Limit calculation of Consortium's payment obligations guaranteed by Toshiba	0.25
SCEG
Nuclear Insurance
Maximum liability assessment per reactor for each nuclear incident	$ 127.3
Maximum Insurance Coverage For Each Nuclear Plant by ANI	450.0
Federal Limit on Public Liability Claims from Nuclear Incident Approximate	13,400.0
Maximum Federal Limit on Public Liability Claims Per Reactor for Each Year	18.9
Maximum Federal Limit on Public Liability Claims per Reactor for each Nuclear Incident at 2/3	84.8
Maximum Federal Limit on Public Liability Claims Per Incident for Each Year	$ 12.6
Inflation adjustment period for nuclear insurance	5
Maximum loss for a single nuclear incident	$ 2,750.0
NEIL Maximum Insurance Coverage of Accidental Property Damage	500.0
NEIL Maximum Insurance Coverage To Nuclear Facility For Property Damage And Outage Costs From Non-Nuclear Event	2,330.0
EMANI Maximum Retrospective Premium Assessment	1.8
EMANI Maximum Insurance Coverage for Summer Station Unit 1 For Property Damage And Outage Costs From Non-Nuclear Event	415.0
NEIL Maximum Prosepective Insurance Premium Per Nuclear Incident	45.8
NEIL Maximum Insurance Coverage to Nuclear Facility for Property Damage and Outage Costs	2,750.0
Environmental
Environmental Remediation Costs Recognized in Regulatory Assets	$ 25.3
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	$ 10.1
Nuclear Generation
EPC Contract Amendment, Fixed Price Option, New Nuclear Construction Completion Bonus	83.0
EPC Contract Amendment, Payment and Performance Bonds	25.0
Estimate of aggregate amount of subcontractor and vendor liens filed	65.0
Aggregate amount of subcontractor and vendor liens paid	$ 27.5
EPC Contract Amendment, Payment And Performance Bonds, Percentage of Billing	15.00%
EPC Contract Amendment, Payment And Performance Bonds, Maximum Aggregate Nominal Coverage	$ 55.0
EPC Contract Amendment, Fixed Price Option, Price For New Nuclear Construction After June 2015	3,345.0
EPC Contract Amendment, Fixed Price Option, Cap On Delay Oriented Liquidated Damages Per New Nuclear Unit	$ 186.0
Dispute Review Board Resolution Without Recourse	less than $5 million
Dispute Review Board Resolution Subject To Litigation	greater than $5 million
November 2016 SCPSC Approved Project Costs above SCPSC 2015 order	$ 831.0
Total New Nuclear Project Cost Nov 2016, excludes AFC and escalation	6,800.0
Total New Nuclear Project Cost 2016, including AFC and escalation	7,700.0
Public Utilities, Authorized Allowable Return on Common Equity, Percentage			10.50%
Summer Station New Units and Transmission Assets [Domain]
Nuclear Generation
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	4,600.0
Summer Station New Units [Domain]
Nuclear Generation
jointly owned utility plant ownership, construction financing cost	$ 3,800.0
Jointly Owned Utility Plant, Proportionate Ownership Share	55.00%
EPC Contract Amendment, Fixed Price Option, New Nuclear Construction Completion Bonus	$ 150.0
EPC Contract Amendment, Payment and Performance Bonds	45.0
Estimate of aggregate amount of subcontractor and vendor liens filed	118.0
Aggregate amount of subcontractor and vendor liens paid	50.0
EPC Contract Amendment, Payment And Performance Bonds, Maximum Aggregate Nominal Coverage	100.0
Nuclear Production Tax Credits	$ 1,400.0
Nuclear Production Tax Credit realization period	8
EPC Contract Amendment, Fixed Price Option, Price For New Nuclear Construction After June 2015	$ 6,082.0
EPC Contract Amendment, Fixed Price Option, Cap On Delay Oriented Liquidated Damages Per New Nuclear Unit	338.0
Scenario, Forecast [Member] | SCEG
Nuclear Generation
Additional ownership in new units				2.00%	2.00%	1.00%
Public Utilities, Authorized Allowable Return on Common Equity, Percentage		10.25%
Maximum [Member] | SCEG
Nuclear Generation
Additional ownership in new units, dollars	$ 850.0

XML

SEGMENT OF BUSINESS INFORMATION (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue	$ 577	$ 592
Revenues	0	0
Net Income (Loss) Available to Common Stockholders, Basic	171	176
Operating Income	316	331
Regulated Operating Revenue, Gas	322	299
Regulated and Unregulated Operating Revenue	1,173	1,172
Segment Assets	18,458		$ 18,707
Electric Operations
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue	577	592
Revenues	1	1
Operating Income	178	198
Segment Assets	12,076		11,929
Gas Distribution
Segment Reporting Information [Line Items]
Revenues	0	1
Operating Income	113	94
Regulated and Unregulated Operating Revenue	322	299
Segment Assets	2,926		2,892
Gas Marketing [Member]
Segment Reporting Information [Line Items]
Revenues	24	22
Net Income (Loss) Available to Common Stockholders, Basic	15	24
Regulated and Unregulated Operating Revenue	274	281
Segment Assets	202		230
All Other [member]
Segment Reporting Information [Line Items]
Revenues	94	98
Net Income (Loss) Available to Common Stockholders, Basic	0	0
Operating Income	0	0
Regulated and Unregulated Operating Revenue	0	0
Segment Assets	997		1,124
Adjustments/Eliminations
Segment Reporting Information [Line Items]
Revenues	(119)	(122)
Net Income (Loss) Available to Common Stockholders, Basic	156	152
Operating Income	25	39
Regulated and Unregulated Operating Revenue	0	0
Segment Assets	2,257		2,532
SCEG
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue	577	592
Operating Income	222	236
Regulated Operating Revenue, Gas	141	124
Net Income (Loss) Attributable to Parent	109	113
Segment Assets	15,965		16,091
Regulated Operating Revenue	719	717
SCEG | Electric Operations
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue	578	593
Operating Income	178	198
Segment Assets	12,076		11,929
SCEG | Gas Distribution
Segment Reporting Information [Line Items]
Operating Income	44	38
Regulated and Unregulated Operating Revenue	141	124
Segment Assets	836		825
SCEG | Adjustments/Eliminations
Segment Reporting Information [Line Items]
Operating Income	0	0
Regulated and Unregulated Operating Revenue	0	0
Net Income (Loss) Attributable to Parent	109	$ 113
Segment Assets	$ 3,053		$ 3,337

XML

AFFILIATED TRANSACTIONS (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Canadys Refined Coal [Member]
Affiliated Transactions [Line Items]
Equity Method Investment, Ownership Percentage	40.00%
Related Party Transaction, Purchases from Related Party	$ 44.6	$ 52.8
Sales to Affiliate	44.4	52.5
Related Party Tax Expense, Due from Affiliates, Current	13.5		$ 16.0
Related Party Tax Expense, Due to Affiliates, Current	13.6		16.1
Energy Marketing [Member]
Affiliated Transactions [Line Items]
Due to Affiliate, Current	8.3		8.8
Cost of Natural Gas Purchases	23.9	22.4
SCANA Services [Member]
Affiliated Transactions [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	72.5	$ 75.6
Accounts Payable, Related Parties, Current	45.8		63.5
SCEG
Affiliated Transactions [Line Items]
Due to Affiliate, Current	100.0		122.0
Due from Affiliate, Current	$ 14.0		$ 16.0