10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2015

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

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

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

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

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

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

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

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

	Description of	Shares Outstanding
Registrant	Common Stock	at October 31, 2015
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 company is filed by such company on its own behalf.  Each company makes no representation as to information relating to the other company.

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).

TABLE OF CONTENTS 

SEPTEMBER 30, 2015

			Page
Cautionary Statement Regarding Forward-Looking Information			3
Definitions			4
PART I. FINANCIAL INFORMATION
SCANA Corporation Financial Section			6
	Item 1.	Financial Statements	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
		Notes to Condensed Consolidated Financial Statements	11
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	40
	Item 4.	Controls and Procedures	41
South Carolina Electric & Gas Company Financial Section			42
	Item 1.	Financial Statements	42
		Condensed Consolidated Balance Sheets	42
		Condensed Consolidated Statements of Income	44
		Condensed Consolidated Statements of Comprehensive Income	44
		Condensed Consolidated Statements of Cash Flows	45
		Notes to Condensed Consolidated Financial Statements	46
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	61
	Item 4.	Controls and Procedures	65
PART II. OTHER INFORMATION			66
	Item 5.	Other Information	66
	Item 6.	Exhibits	66
Signatures			67
Exhibit Index			68

2

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

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

(2) legislative and regulatory actions, particularly changes in rate regulation, regulations governing electric grid reliability and

pipeline integrity, environmental regulations, and actions affecting the construction of new nuclear units;

(3) current and future litigation;

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

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

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

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

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

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

other sources of liquidity;

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

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

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

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

(13) the results of efforts to license, site, construct and finance facilities for electric generation and transmission, including nuclear generating facilities, and the results of efforts to operate its electric and gas systems and assets in accordance with acceptable performance standards;

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

(15) the ability of suppliers, both domestic and international, to timely provide the labor, secure processes, components,

parts, tools, equipment and other supplies needed, at agreed upon quality and prices, for our construction program, operations and maintenance;

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

(17) 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;

(18) the availability of skilled and experienced human resources to properly manage, operate, and grow the Company’s

businesses;

(19) labor disputes;

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

(21) changes in taxes and tax credits, including production tax credits for new nuclear units;

(22) inflation or deflation;

(23) compliance with regulations;

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

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

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

3

DEFINITIONS

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

TERM	MEANING
AFC	Allowance for Funds Used During Construction
ANI	American Nuclear Insurers
AOCI	Accumulated Other Comprehensive Income
ARO	Asset Retirement Obligation
BLRA	Base Load Review Act
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
CERCLA	Comprehensive Environmental Response, Compensation and Liability Act
CGT	Carolina Gas Transmission Corporation
COL	Combined Construction and Operating License
Company	SCANA, together with its consolidated subsidiaries
Consolidated SCE&G	SCE&G and its consolidated affiliates
Consortium	A consortium consisting of WEC and Stone & Webster
Court of Appeals	United States Court of Appeals for the District of Columbia
CSAPR	Cross-State Air Pollution Rule
CUT	Customer Usage Tracker
CWA	Clean Water Act
DER	Distributed Energy Resource
DHEC	South Carolina Department of Health and Environmental Control
DOE	United States Department of Energy
DSM Programs	Demand reduction and energy efficiency programs
ELG Rule	New federal effluent limitation guidelines for steam electric generating units
Energy Marketing	The divisions of SEMI, excluding SCANA Energy
EPA	United States Environmental Protection Agency
EPC Contract	Engineering, Procurement and Construction Agreement dated May 23, 2008
FASB	Financial Accounting Standards Board
FERC	United States Federal Energy Regulatory Commission
Fuel Company	South Carolina Fuel Company, Inc.
GAAP	Accounting principles generally accepted in the United States of America
GENCO	South Carolina Generating Company, Inc.
GHG	Greenhouse Gas
GPSC	Georgia Public Service Commission
GWh	Gigawatt hour
IRP	Integrated Resource Plan
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
NPDES	National Permit Discharge Elimination System
NRC	United States Nuclear Regulatory Commission
NSPS	New Source Performance Standards
Nuclear Waste Act	Nuclear Waste Policy Act of 1982
NYMEX	New York Mercantile Exchange
OCI	Other Comprehensive Income
October 2015 Amendment	Amendment to the EPC Contract dated October 27, 2015
ORS	South Carolina Office of Regulatory Staff
PGA	Purchased Gas Adjustment
Price-Anderson	Price-Anderson Indemnification Act
PSNC Energy	Public Service Company of North Carolina, Incorporated
Retail Gas Marketing	SCANA Energy
RSA	Natural Gas Rate Stabilization Act
Santee Cooper	South Carolina Public Service Authority
SCANA	SCANA Corporation, the parent company
SCANA Energy	A division of SEMI which markets natural gas in Georgia
SCE&G	South Carolina Electric & Gas Company
SCI	SCANA Communications, Inc.
SCPSC	Public Service Commission of South Carolina
SEC	United States Securities and Exchange Commission
SEMI	SCANA Energy Marketing, Inc.
Spirit Communications	SCTG Communications, Inc. (a wholly owned subsidiary of SCTG, LLC) d/b/a Spirit Communications
Stone & Webster	CB&I Stone & Webster, Inc., a subsidiary of CB&I
Summer Station	V. C. Summer Nuclear Station
VIE	Variable Interest Entity
WEC	Westinghouse Electric Company LLC

5

PART I.  FINANCIAL INFORMATION

SCANA CORPORATION FINANCIAL SECTION

ITEM 1. F INANCIAL STATEMENTS

SCANA CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited) 

Millions of dollars	September 30, 2015			December 31, 2014
Assets
Utility Plant In Service	$	12,692		$	12,289
Accumulated Depreciation and Amortization	(4,268		)	(4,088		)
Construction Work in Progress	3,790			3,323
Plant to be Retired, Net	—			169
Nuclear Fuel, Net of Accumulated Amortization	305			329
Goodwill, net of writedown of $230	210			210
Utility Plant, Net	12,729			12,232
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation of $122 and $122	281			284
Assets held in trust, net-nuclear decommissioning	113			113
Other investments	73			75
Nonutility Property and Investments, Net	467			472
Current Assets:
Cash and cash equivalents	54			137
Receivables, net of allowance for uncollectible accounts of $5 and $7	618			838
Inventories (at average cost):
Fuel and gas supply	164			222
Materials and supplies	147			139
Prepayments	132			320
Other current assets	106			148
Assets held for sale	—			341
Total Current Assets	1,221			2,145
Deferred Debits and Other Assets:
Regulatory assets	1,884			1,823
Other	205			180
Total Deferred Debits and Other Assets	2,089			2,003
Total	$	16,506		$	16,852

See Notes to Condensed Consolidated Financial Statements.

6

Millions of dollars	September 30, 2015			December 31, 2014
Capitalization and Liabilities
Common Stock - no par value (shares outstanding: September 30, 2015 - 142.9 million; December 31, 2014 - 142.7 million)	$	2,391		$	2,378
Retained Earnings	3,098			2,684
Accumulated Other Comprehensive Loss	(70		)	(75		)
Total Common Equity	5,419			4,987
Long-Term Debt, net	6,018			5,531
Total Capitalization	11,437			10,518
Current Liabilities:
Short-term borrowings	264			918
Current portion of long-term debt	16			166
Accounts payable	312			520
Customer deposits and customer prepayments	110			98
Taxes accrued	183			182
Interest accrued	85			83
Dividends declared	76			73
Liabilities held for sale	—			52
Derivative financial instruments	125			233
Other	123			208
Total Current Liabilities	1,294			2,533
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,839			1,866
Deferred investment tax credits	26			28
Asset retirement obligations	489			563
Postretirement benefits	320			315
Regulatory liabilities	859			814
Other	242			215
Total Deferred Credits and Other Liabilities	3,775			3,801
Commitments and Contingencies (Note 9)	—			—
Total	$	16,506		$	16,852

See Notes to Condensed Consolidated Financial Statements.

7

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Millions of dollars, except per share amounts	2015			2014			2015			2014
Operating Revenues:
Electric	$	742		$	739		$	2,008		$	2,027
Gas - regulated	112			132			610			740
Gas - nonregulated	214			250			805			969
Total Operating Revenues	1,068			1,121			3,423			3,736
Operating Expenses:
Fuel used in electric generation	187			212			525			636
Purchased power	14			13			38			54
Gas purchased for resale	260			304			1,030			1,291
Other operation and maintenance	182			169			527			523
Depreciation and amortization	75			96			267			286
Other taxes	58			58			176			174
Total Operating Expenses	776			852			2,563			2,964
Gain on sale of CGT, net of transaction costs	—			—			235			—
Operating Income	292			269			1,095			772
Other Income (Expense):
Other income	19			18			56			103
Other expense	(16		)	(12		)	(44		)	(39		)
Gain on sale of SCI, net of transaction costs	—			—			107			—
Interest charges, net of allowance for borrowed funds used during construction of $5, $5, $12 and $13	(81		)	(79		)	(236		)	(231		)
Allowance for equity funds used during construction	8			11			20			26
Total Other Income (Expense)	(70		)	(62		)	(97		)	(141		)
Income Before Income Tax Expense	222			207			998			631
Income Tax Expense	73			63			350			198
Net Income	$	149		$	144		$	648		$	433
Basic and Diluted Earnings Per Share of Common Stock	$	1.04		$	1.01		$	4.53		$	3.06
Weighted Average Common Shares Outstanding (millions)	142.9			142.1			142.9			141.6
Dividends Declared Per Share of Common Stock	$	0.545		$	0.525		$	1.635		$	1.575

See Notes to Condensed Consolidated Financial Statements.

8

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited) 

	Three Months Ended September 30,						Nine Months Ended September 30,
Millions of dollars	2015			2014			2015			2014
Net Income	$	149		$	144		$	648		$	433
Other Comprehensive Income (Loss), net of tax:
Unrealized Gains (Losses) on Cash Flow Hedging Activities:
Unrealized gains (losses) on cash flow hedging activities arising during period, net of tax of $(4), $(1), $(5) and $(2)	(7		)	(2		)	(8		)	(3		)
Cash flow hedging activities reclassified to interest expense, net tax of $1, $1, $3, and $3	2			2			6			5
Cash flow hedging activities reclassified to gas purchased for resale, net of tax of $-, $-, $6, and $(3)	1			—			10			(4		)
Net unrealized gains (losses) on cash flow hedging activities	(4		)	—			8			(2		)
Deferred cost of employee benefit plans, net of tax of $-, $-, $(2) and $-	1			1			(3		)	1
Other Comprehensive Income (Loss)	(3		)	1			5			(1		)
Total Comprehensive Income	$	146		$	145		$	653		$	432

See Notes to Condensed Consolidated Financial Statements.

9

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited) 

	Nine Months Ended September 30,
Millions of dollars	2015			2014
Cash Flows From Operating Activities:
Net income	$	648		$	433
Adjustments to reconcile net income to net cash provided from operating activities:
Gain on sale of subsidiaries	(355		)	—
Losses from equity method investments	2			2
Deferred income taxes, net	(98		)	63
Depreciation and amortization	276			298
Amortization of nuclear fuel	41			31
Allowance for equity funds used during construction	(20		)	(26		)
Carrying cost recovery	(9		)	(7		)
Changes in certain assets and liabilities:				—
Receivables	192			111
Inventories	2			(34		)
Prepayments	196			(99		)
Regulatory assets	92			(171		)
Regulatory liabilities	9			(133		)
Accounts payable	(85		)	(18		)
Taxes accrued	2			(69		)
Pension and other post retirement benefits	(1		)	(13		)
Derivative financial instruments	(108		)	105
Other assets	73			25
Other liabilities	(50		)	60
Net Cash Provided From Operating Activities	807			558
Cash Flows From Investing Activities:
Property additions and construction expenditures	(851		)	(778		)
Proceeds from sale of subsidiaries	647			—
Proceeds from investments (including derivative collateral returned)	872			204
Purchase of investments (including derivative collateral posted)	(872		)	(247		)
Payments upon interest rate derivative contract settlement	(152		)	(34		)
Proceeds upon interest rate derivative contract settlement	10			—
Net Cash Used For Investing Activities	(346		)	(855		)
Cash Flows From Financing Activities:
Proceeds from issuance of common stock	14			75
Proceeds from issuance of long-term debt	491			294
Repayment of long-term debt	(164		)	(17		)
Dividends	(231		)	(220		)
Short-term borrowings, net	(654		)	111
Net Cash Provided From (Used for) Financing Activities	(544		)	243
Net Decrease In Cash and Cash Equivalents	(83		)	(54		)
Cash and Cash Equivalents, January 1	137			136
Cash and Cash Equivalents, September 30	$	54		$	82
Supplemental Cash Flow Information:
Cash paid for– Interest (net of capitalized interest of $12 and $13)	$	224		$	225
– Income taxes	184			246
Noncash Investing and Financing Activities:
Accrued construction expenditures	85			108
Capital leases	5			4

 See Notes to Condensed Consolidated Financial Statements.

10

SCANA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

For the Three and Nine Months Ended September 30, 2015 and 2014

(Unaudited)

The following notes should be read in conjunction with the Notes to Consolidated Financial Statements appearing in SCANA’s Annual Report on Form 10-K for the year ended December 31, 2014. These are interim financial statements and, due to the seasonality of the Company’s business and matters that may occur during the rest of the year, the amounts reported in the Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the full year.  In the opinion of management, the information furnished herein reflects all adjustments, all of a normal recurring nature, which are necessary for a fair statement of the results for the interim periods reported.

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Plant to be Retired

At December 31, 2014, SCE&G expected to retire three units that are or were coal-fired by 2020, which was prior to the end of the previously estimated useful lives over which the units were being depreciated. As such, these units were identified as Plant to be Retired. In the third quarter of 2015, in connection with the adoption of a customary depreciation study and related analysis, SCE&G determined that these three units would not likely be retired by 2020 (see Note 2), and their depreciation rates were set to recover the units' net carrying value over their respective revised useful lives. Accordingly, the net carrying value of these units is no longer classified as Plant to be Retired at September 30, 2015.

Asset Management and Supply Service Agreements

PSNC Energy utilizes asset management and supply service agreements with counterparties for certain natural gas storage facilities.  Such counterparties held 50% and 48% of PSNC Energy’s natural gas inventory at September 30, 2015

and December 31, 2014, respectively, with a carrying value of $19.1 million and $26.1 million, respectively, through either capacity release or agency relationships.  Under the terms of the asset management agreements, PSNC Energy receives storage asset management feesof which 75% are credited to rate payers. No fees are received under supply service agreements. The agreements, which expired on March 31, 2015, were replaced with similar agreements scheduled to expire March 31, 2017.

Income Statement Presentation

The Company presents the revenues and expenses of its regulated businesses and its retail natural gas marketing businesses (including those activities of segments described in Note 10) within operating income, and it presents all other activities within other income (expense). Consistent with this presentation, the gain on the sale of CGT is reflected within operating income and the gain on the sale of SCI is reflected within other income (expense).

New Accounting Matters

In April 2014, the FASB issued accounting guidance for reporting discontinued operations and disclosures of disposals of components of an entity. Under this guidance, only those discontinued operations which represent a strategic shift that will have a major effect on an entity’s operations and financial results should be reported as discontinued operations in the financial statements. As permitted, the Company adopted this guidance for the period ended December 31, 2014.

In May 2014, the FASB issued accounting guidance for revenue arising from contracts with customers that supersedes most current revenue recognition guidance, including industry-specific guidance. The new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. After the FASB's delay in the effective date of the revenue guidance by one year, the Company is required to adopt this guidance in the first quarter of 2018 and early adoption is permitted beginning in the first

11

quarter of 2017. The Company has not determined the impact this guidance will have on its results of operations, cash flows or financial position.

In April 2015, the FASB issued accounting guidance intended to simplify the presentation of debt issuance costs by requiring that such costs be deducted from the carrying amounts related to debt liabilities when presented in the balance sheet. As permitted, the Company expects to early adopt this guidance in the fourth quarter of 2015.  The Company does not expect the adoption of this guidance to have a significant impact on its financial position.  The guidance will not affect the Company’s results of operations or cash flows.

In April 2015, the FASB issued accounting guidance related to fees paid by a customer in a cloud computing arrangement.  Among other things, the guidance clarifies how to account for a software license element included in a cloud computing arrangement, and makes explicit that a cloud computing arrangement not containing a software license element should be accounted for as a service contract. The Company has evaluated this guidance and has determined it will not significantly impact the Company’s results of operations, cash flows or financial position. The Company expects to adopt this guidance in the first quarter of 2016.

In July 2015, the FASB issued accounting guidance intended to simplify the subsequent measurement of inventory cost by requiring most inventory to be measured at the lower of cost and net realizable value. The Company expects to adopt this guidance when required in the first quarter of 2017. The Company is evaluating this guidance and has not determined what impact it will have on its results of operations, cash flows or financial position.

2. RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric - Cost of Fuel

SCE&G's retail electric rates include a cost of fuel component approved by the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased by SCE&G.

Pursuant to an April 2014 SCPSC order, SCE&G increased its base fuel cost component by approximately $10.3 million for the 12-month period beginning with the first billing cycle of May 2014. The base fuel cost increase was offset by a reduction in SCE&G's rate rider related to pension costs approved by the SCPSC in March 2014. In addition, pursuant to the April 2014 order, electric revenue for 2014 was reduced by approximately $46 million for adjustments to the fuel cost component and related under-collected fuel balance. Such adjustments are fully offset by the recognition within other income of gains realized from the late 2013 settlement of certain interest rate derivatives which had been entered into in anticipation of the issuance of long-term debt, which gains had been deferred as a regulatory liability. The order also provided for the accrual of certain debt-related carrying costs on its under-collected balance of base fuel costs during the period May 1, 2014 through April 30, 2015.

The cost of fuel includes amounts paid by SCE&G pursuant to the Nuclear Waste Act for the disposal of spent nuclear fuel. As a result of a November 2013 decision by the Court of Appeals, the DOE set the Nuclear Waste Act fee to zero effective May 16, 2014. The impact of changes to the Nuclear Waste Act fee is considered during annual fuel rate proceedings.

By order dated April 30, 2015, the SCPSC approved a settlement agreement among SCE&G and certain other parties in which SCE&G agreed to decrease the total fuel cost component of retail electric rates. Under this order, SCE&G is to recover an amount equal to its under-collected balance of base fuel and variable environmental costs as of April 30, 2015, over the subsequent 12-month period beginning with the first billing cycle of May 2015.

By order dated July 15, 2015, the SCPSC approved a settlement agreement among SCE&G and certain other parties concerning SCE&G's petition for approval to participate in a DER program and to recover DER program costs as a separate component of SCE&G's overall fuel factor. Under this order, SCE&G will, among other things, develop renewable energy facilities with a nameplate capacity of at least 84.5 MW by the end of 2020 and have at least 30 MW of utility-scale solar capacity in service by the end of 2016. The order also requires SCE&G to develop incentives for solar energy generated by residential and commercial customers. SCE&G will also make incentives available for residential customers receiving solar power from community solar-programs.

By order dated September 16, 2015, the SCPSC approved SCE&G's request to adopt lower depreciation rates for electric and common plant effective January 1, 2015 resulting in $29 million (or $.12 cents per share) in lower depreciation

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expense annually. These rates were based on the results of a depreciation study conducted by SCE&G using utility plant balances as of December 31, 2014. In connection with the adoption of the revised depreciation rates, SCE&G recorded lower depreciation expense of approximately $22 million (or $.09 cents per share) in the third quarter of 2015, and pursuant to the SCPSC order, SCE&G reduced its electric operating revenues by approximately $14.5 million (or $.06 cents per share) with an offset to under-collected fuel included within Receivables in the balance sheet. Accordingly, the Company's net income for each of the three and nine months ended September 30, 2015, increased approximately $4.5 million as a result of this change in estimate.

Electric - Base Rates

Pursuant to an SCPSC order, SCE&G removes from rate base deferred income tax assets arising from capital expenditures related to the New Units and accrues carrying costs on those amounts during periods in which they are not included in rate base.  Such carrying costs are determined at SCE&G’s weighted average long-term debt borrowing rate and are recorded as a regulatory asset and other income. Carrying costs during the three and nine months ended September 30, 2015 totaled $2.4 million and $6.5 million, respectively, and during the three and nine months ended September 30, 2014 totaled $1.6 million and $4.1 million, respectively. SCE&G anticipates that when the New Units are placed in service and accelerated tax depreciation is recognized on them, these deferred income tax assets will decline. When these assets are fully offset by related deferred income tax liabilities, the carrying cost accruals will cease, and the regulatory asset will begin to be amortized.

The SCPSC has approved a suite of DSM Programs for development and implementation. SCE&G offers to its retail electric customers several distinct programs designed to assist customers in reducing their demand for electricity and improving their energy efficiency. SCE&G submits annual filings to the SCPSC related to these programs which include actual program costs, net lost revenues (both forecasted and actual), customer incentives, and net program benefits, among other things. As actual DSM Program costs are incurred, they are deferred as regulatory assets (see Regulatory Assets and Regulatory Liabilities below) and recovered through a rate rider approved by the SCPSC. The rate rider also provides for recovery of net lost revenues and for a shared savings incentive. The SCPSC approved the following rate riders pursuant to the annual DSM Programs filings, which went into effect as indicated below:

Year	Effective	Amount
2015	First billing cycle of May	$	32.0	million
2014	First billing cycle of May	$	15.4	million
2013	First billing cycle of May	$	16.9	million

In April 2014, the SCPSC issued an order approving, among other things, SCE&G’s request to utilize approximately $17.8 million of the gains from the late 2013 settlement of certain interest rate derivative instruments, previously deferred as regulatory liabilities, to offset a portion of SCE&G’s DSM Programs rate rider. This order also allowed SCE&G to apply $5.0 million of its storm damage reserve and $5.0 million of the gains from the settlement of certain interest rate derivative instruments to offset previously deferred amounts.

Electric – BLRA

Under the BLRA, SCE&G may file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation. Through 2015, requested rate adjustments have been based on SCE&G's updated cost of debt and capital structure and on an allowed return on common equity of 11.0%. The SCPSC has approved recovery of the following amounts under the BLRA effective for bills rendered on and after October 30 in the following years:

Year	Action			Amount
2015	2.6	%	Increase	$	64.5	million
2014	2.8	%	Increase	$	66.2	million
2013	2.9	%	Increase	$	67.2	million

In September 2015 the SCPSC approved a revision to the allowed return on equity for new nuclear construction from 11.0% to 10.5%. This revised return on equity will be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2016, until such time as the New Units are completed. See Note 9.

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Gas - SCE&G

The RSA is designed to reduce the volatility of costs charged to customers by allowing for more timely recovery of the costs that regulated utilities incur related to natural gas infrastructure. The SCPSC has approved the following rate changes pursuant to annual RSA filings effective with the first billing cycle of November in the following years: 

Year	Action			Amount
2015	No change			-
2014	0.6	%	Decrease	$	2.6	million
2013	No change			-

SCE&G's natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred, including transportation costs. SCE&G's gas rates are calculated using a methodology which may adjust the cost of gas monthly based on a 12-month rolling average, and its gas purchasing policies and practices are reviewed annually by the SCPSC. The annual review conducted for the 12-month period ended July 31, 2014 resulted in the SCPSC issuing an order finding that SCE&G's gas purchasing policies and practices during the review period were reasonable and prudent. SCE&G's 2015 annual PGA hearing was held on November 5, 2015 and the SCPSC's decision is pending.

Gas - PSNC Energy

PSNC Energy's Rider D rate mechanism allows it to recover from customers all prudently incurred gas costs and certain related uncollectible expenses as well as losses on negotiated gas and transportation sales.

PSNC Energy establishes rates using a benchmark cost of gas approved by the NCUC, which may be periodically adjusted to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs as necessary to track these changes and accounts for any over- or under-collection of the delivered cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy’s gas purchasing practices annually. In addition, PSNC Energy utilizes a CUT which allows it to adjust its base rates semi-annually for residential and commercial customers based on average per customer consumption.

In October 2015, in connection with PSNC Energy's 2015 Annual Prudence Review, the NCUC determined that PSNC Energy's gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12 months ended March 31, 2015.

In May 2014, the NCUC issued an order requiring utilities to adjust rates to reflect changes in the state corporate income tax rate that had been enacted by the North Carolina legislature and to file a proposal to refund amounts previously collected on a provisional basis. Pursuant to the order, PSNC Energy lowered its rates effective July 1, 2014, and refunded the amounts previously collected through the normal operation of its Rider D rate mechanism. These amounts were not significant for any period presented.

Regulatory Assets and Regulatory Liabilities

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

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Millions of dollars	September 30, 2015		December 31, 2014
Regulatory Assets:
Accumulated deferred income taxes	$	284	$	284
Under-collections - electric fuel adjustment clause	—		20
Environmental remediation costs	39		40
AROs and related funding	376		366
Franchise agreements	23		26
Deferred employee benefit plan costs	328		350
Planned major maintenance	—		2
Deferred losses on interest rate derivatives	538		453
Deferred pollution control costs	35		36
Unrecovered plant	128		137
DSM Programs	59		56
Carrying costs on deferred tax assets related to nuclear construction	15		9
Pipeline integrity management costs	16		9
Other	43		35
Total Regulatory Assets	$	1,884	$	1,823

Regulatory Liabilities:
Accumulated deferred income taxes	$	22	$	22
Asset removal costs	729		703
Storm damage reserve	6		6
Deferred gains on interest rate derivatives	87		82
Planned major maintenance	12		—
Other	3		1
Total Regulatory Liabilities	$	859	$	814

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

Under-collections - electric fuel adjustment clause represent amounts due from customers pursuant to the fuel adjustment clause as approved by the SCPSC which are expected to be recovered in retail electric rates over periods exceeding 12 months. 

Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by the Company, and are expected to be recovered over periods of up to approximately 24 years.

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

Franchise agreements represent costs associated with electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. Based on an SCPSC order, SCE&G is recovering these amounts through cost of service rates through approximately 2021.

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

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Planned major maintenance related to certain fossil fueled turbine/generation equipment and nuclear refueling outages is accrued in periods other than when incurred, pursuant to specific SCPSC orders. SCE&G collects and accrues $18.4 million annually for fossil fueled turbine/generation equipment maintenance, and collects and accrues $17.2 million annually for nuclear-related refueling charges.

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

Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the scrubbers installed at certain coal-fired generating plants pursuant to specific regulatory orders. Such costs are being recovered through utility rates through 2045.

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

DSM Programs represent deferred costs associated with such programs. As a result of an April 2015 SCPSC order, deferred costs are currently being recovered over approximately five years through an approved rate rider. 

Carrying costs on deferred tax assets related to nuclear construction are calculated on accumulated deferred income tax assets associated with the New Units which are not part of electric rate base using the weighted average long-term debt cost of capital. These carrying costs will be amortized over ten years beginning in approximately 2021.

Pipeline integrity management costs represent costs incurred to comply with regulatory requirements related to certain natural gas pipelines located near moderate to high density populations. Such costs at SCE&G will be amortized at $1.9 million annually beginning in November 2015. Such costs at PSNC Energy will be considered for recovery through rates in its next general rate proceeding.

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

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

The storm damage reserve represents an SCPSC-approved collection through SCE&G electric rates, capped at $100 million, which can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year. Pursuant to specific regulatory orders, SCE&G has suspended storm damage reserve collection through rates indefinitely. During the nine months ended September 30, 2015, no amounts were applied to offset incremental storm damage costs.

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

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3.COMMON EQUITY

Changes in common equity during the nine months ended September 30, 2015 and 2014 were as follows:

	Common Stock									Accumulated Other Comprehensive Income (Loss)
Millions	Shares	Outstanding Amount		Treasury Shares			Retained Earnings			Gains(Losses) on Cash Flow Hedges			Deferred Employee Benefit Plans			Total AOCI			Total Common Equity
Balance as of January 1, 2015	143	$	2,388	$	(10	)	$	2,684		$	(63	)	$	(12	)	$	(75	)	$	4,987
Net Income							648												648
Other Comprehensive Income (Loss):
Losses during the period										(8		)	(3		)	(11		)	(11		)
Reclassified from AOCI										16			—			16			16
Total Comprehensive Income (Loss)							648			8			(3		)	5			653
Issuance of Common Stock	—	14		(1		)													13
Dividends Declared							(234		)										(234		)
Balance as of September 30, 2015	143	$	2,402	$	(11	)	$	3,098		$	(55	)	$	(15	)	$	(70	)	$	5,419
Balance as of January 1, 2014	141	$	2,289	$	(9	)	$	2,444		$	(52	)	$	(8	)	$	(60	)	$	4,664
Net Income							433												433
Other Comprehensive Income:
Losses during the period										(3		)	—			(3		)	(3		)
Reclassified from AOCI										1			1			2			2
Total Comprehensive Income							433			(2		)	1			(1		)	432
Issuance of Common Stock	1	76		(1		)													75
Dividends Declared							(223		)										(223		)
Balance as of September 30, 2014	142	$	2,365	$	(10	)	$	2,654		$	(54	)	$	(7	)	$	(61	)	$	4,948

Gains and losses on cash flow hedges reclassified during the nine months ended September 30, 2015 resulted in higher interest expense of $6 million and higher cost of gas purchased for resale of $10 million. Such reclassifications during the comparable period in 2014 resulted in higher interest expense of $5 million and lower cost of gas purchased for resale of $4 million.

SCANA had 200 million shares of common stock authorized as of September 30, 2015 and December 31, 2014.

4. LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

In May 2014, SCE&G issued $300 million of 4.5% first mortgage bonds due June 1, 2064. Proceeds from this sale were used to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes.

On February 2, 2015, SCANA redeemed prior to maturity $150 million of its 7.7% junior subordinated notes at their face value.

In May 2015, SCE&G issued $500 million of 5.1% first mortgage bonds due June 1, 2065. Proceeds from this sale were used to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes.

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

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Liquidity

SCANA, SCE&G (including Fuel Company) and PSNC Energy had available the following committed LOC, and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations: 

	SCANA						SCE&G						PSNC Energy
Millions of dollars	September 30, 2015			December 31, 2014			September 30, 2015			December 31, 2014			September 30, 2015			December 31, 2014
Lines of credit:
Total committed long-term	$	300		$	300		$	1,400		$	1,400		$	100		$	100
Outstanding commercial paper ( 270 or fewer days)	$	14		$	179		$	234		$	709		$	16		$	30
Weighted average interest rate	0.66		%	0.54		%	0.44		%	0.52		%	0.45		%	0.65		%
Letters of credit supported by LOC	$	3		$	3		$	0.3		$	0.3		—			—
Available	$	283		$	118		$	1,166		$	691		$	84		$	70

SCANA, SCE&G (including Fuel Company) and PSNC Energy are parties to five-year credit agreements in the amounts of $300 million, $1.2 billion (of which $500 million relates to Fuel Company) and $100 million, respectively, which expire in October 2019. In addition, SCE&G is a party to a three-year credit agreement in the amount of $200 million, which expires in October 2016. These credit agreements are used for general corporate purposes, including liquidity support for each company's commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, certain fossil fuels, and emission and other environmental allowances.  These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N.A. and Morgan Stanley Bank, N.A. each provide 10.7% of the aggregate $1.8 billion credit facilities, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A., Credit Suisse AG, Cayman Island Branch and UBS Loan Finance LLC each provide 8.9%, and Branch Banking and Trust Company, Union Bank, N.A. and U.S. Bank National Association each provide 6.3%.  Two other banks provide the remaining support. The Company pays fees to the banks as compensation for maintaining the committed lines of credit. Such fees were not material in any period presented.

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

5. INCOME TAXES

Between 2013 and 2015, in addition to filing current year tax returns, the Company amended certain of its tax returns. These returns claimed certain tax-defined research and development deductions and credits. In connection with these filings, the Company recorded an unrecognized tax benefit of $18 million. If recognized, $14 million of the tax benefit would affect the Company’s effective tax rate. It is reasonably possible that this tax benefit will increase by an additional $2 million within the next 12 months. It is also reasonably possible that this tax benefit may decrease by $8 million within the next 12 months. No other material changes in the status of the Company’s tax positions have occurred through September 30, 2015.

The Company recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses.  The Company has not recorded any interest expense or penalties associated with these positions.

6. DERIVATIVE FINANCIAL INSTRUMENTS

The Company recognizes all derivative instruments as either assets or liabilities in the statement of financial position and measures those instruments at fair value. The Company recognizes changes in the fair value of derivative instruments either in earnings, as a component of OCI or, for regulated subsidiaries, within regulatory assets or regulatory liabilities, depending upon the intended use of the derivative and the resulting designation. 

Policies and procedures and risk limits are established to control the level of market, credit, liquidity and operational and administrative risks assumed by the Company.  SCANA’s Board of Directors has delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and oversee and review the risk management process and infrastructure for SCANA and each of its subsidiaries.  The Risk Management Committee, which is comprised of certain officers, including the Company’s Risk Management Officer and senior officers, apprises the Audit Committee of the Board of Directors with regard to the management of risk and brings to their attention

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significant areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions.

Commodity Derivatives

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

PSNC Energy hedges natural gas purchasing activities using over-the-counter options and NYMEX futures and options.  PSNC Energy’s tariffs include a provision for the recovery of actual gas costs incurred, including any costs of hedging.  PSNC Energy records premiums, transaction fees, margin requirements and any realized gains or losses from its hedging program in deferred accounts as a regulatory asset or liability for the under- or over-recovery of gas costs.  These derivative financial instruments are not designated as hedges for accounting purposes.

Unrealized gains and losses on qualifying cash flow hedges of nonregulated operations are deferred in AOCI.  When the hedged transactions affect earnings, previously recorded gains and losses are reclassified from AOCI to cost of gas.  The effects of gains or losses resulting from these hedging activities are either offset by the recording of the related hedged transactions or are included in gas sales pricing decisions made by the business unit.

As an accommodation to certain customers, SEMI, as part of its energy management services, offers fixed price supply contracts which are accounted for as derivatives.  These sales contracts are offset by the purchase of supply futures and swaps which are also accounted for as derivatives. Neither the sales contracts nor the related supply futures and swaps are designated as hedges for accounting purposes.

Interest Rate Swaps

The Company may use interest rate swaps to manage interest rate risk and exposure to changes in fair value attributable to changes in interest rates on certain debt issuances.  The Company synthetically converts variable rate debt to fixed rate debt using swaps that are designated as cash flow hedges. Periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense.

In anticipation of the issuance of debt, the Company may use treasury rate locks or forward starting swap agreements that are designated as cash flow hedges. For GENCO, the effective portions of changes in fair value and payments made or received upon termination of such agreements are recorded in regulatory assets or regulatory liabilities. For the holding company or nonregulated subsidiaries, such amounts are recorded in AOCI. Such amounts are amortized to interest expense over the term of the underlying debt. Ineffective portions of fair value changes are recognized in income.

Pursuant to regulatory orders, interest rate derivatives entered into by SCE&G after October 2013 are not designated as cash flow hedges, and all related fair value changes and settlement amounts are recorded as regulatory assets or liabilities. Interest rate derivatives entered into before October 2013 were designated as cash flow hedges, and for such instruments only the effective portion of fair value changes and settlement amounts are recorded in regulatory assets or regulatory liabilities. Upon settlement, losses on swaps are amortized over the lives of related debt issuances, and gains are applied to under-collected fuel, are amortized to interest expense or are applied as otherwise directed by the SCPSC.

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

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Quantitative Disclosures Related to Derivatives

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

	Commodity and Other Energy Management Contracts (in MMBTU)
Hedge designation	Gas Distribution	Retail Gas Marketing	Energy Marketing	Total
As of September 30, 2015
Commodity contracts	9,270,000	11,788,000	4,335,500	25,393,500
Energy management contracts (a)	—	—	32,211,282	32,211,282
Total (a)	9,270,000	11,788,000	36,546,782	57,604,782
As of December 31, 2014
Commodity contracts	6,840,000	7,951,000	3,446,720	18,237,720
Energy management contracts (b)	—	—	37,495,339	37,495,339
Total (b)	6,840,000	7,951,000	40,942,059	55,733,059

(a)  Includes an aggregate 1,246,230 MMBTU related to basis swap contracts in Energy Marketing.

(b)  Includes an aggregate 933,893 MMBTU related to basis swap contracts in Energy Marketing.

The Company was party to interest rate swaps designated as cash flow hedges with aggregate notional amounts of $120.0 million at September 30, 2015 and $124.4 million at December 31, 2014. The Company was party to interest rate swaps not designated as cash flow hedges with an aggregate notional amount of $1.2 billion at September 30, 2015 and $1.1 billion at December 31, 2014.

The fair value of interest rate and energy-related derivatives was as follows:

Fair Values of Derivative Instruments
Millions of dollars	Balance Sheet Location	Asset		Liability
As of September 30, 2015
Designated as hedging instruments
Interest rate contracts	Derivative financial instruments			$	4
	Other deferred credits and other liabilities			31
Commodity contracts	Other current assets			1
	Derivative financial instruments			6
Total				$	42
Not designated as hedging instruments
Interest rate contracts	Other deferred debits and other assets	$	6	—
	Derivative financial instruments	—		$	107
	Other deferred credits and other liabilities	—		60
Energy management contracts	Other current assets	10		2
	Derivative financial instruments	—		8
	Other deferred debits and other assets	5		—
	Other deferred credits and other liabilities	—		4
Total		$	21	$	181

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Millions of dollars	Balance Sheet Location	Asset		Liability
As of December 31, 2014
Designated as hedging instruments
Interest rate contracts	Derivative financial instruments			$	5
	Other deferred credits and other liabilities			28
Commodity contracts	Other current assets			1
	Derivative financial instruments			11
Total				$	45
Not designated as hedging instruments
Interest rate contracts	Derivative financial instruments	—		$	207
	Other deferred credits and other liabilities	—		17
Commodity contracts	Other current assets	$	1	—
Energy management contracts	Other current assets	15		5
	Derivative financial instruments	—		10
	Other deferred debits and other assets	5		—
	Other deferred credits and other liabilities	—		5
Total		$	21	$	244

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

Derivatives Designated as Fair Value Hedges

The Company had no interest rate or commodity derivatives designated as fair value hedges for any period presented.

Derivatives in Cash Flow Hedging Relationships

	Loss Deferred in Regulatory Accounts							Loss Reclassified from Deferred Accounts into Income
	(Effective Portion)							(Effective Portion)
Millions of dollars	2015			2014			Location	2015			2014
Three Months Ended September 30,
Interest rate contracts	$	(3	)	$	(1	)	Interest expense	$	(1	)	$	(1	)
Nine Months Ended September 30,
Interest rate contracts	$	(3	)	$	(5	)	Interest expense	$	(2	)	$	(2	)

	Gain (Loss) Recognized in OCI, net of tax							Gain (Loss) Reclassified from AOCI into Income, net of tax
	(Effective Portion)							(Effective Portion)
Millions of dollars	2015			2014			Location	2015			2014
Three Months Ended September 30,
Interest rate contracts	$	(3	)	—			Interest expense	$	(2	)	$	(2	)
Commodity contracts	(4		)	$	(2	)	Gas purchased for resale	(1		)	—
Total	$	(7	)	$	(2	)		$	(3	)	$	(2	)
Nine Months Ended September 30,
Interest rate contracts	$	(3	)	$	(4	)	Interest expense	$	(6	)	$	(5	)
Commodity contracts	(5		)	1			Gas purchased for resale	(10		)	4
Total	$	(8	)	$	(3	)		$	(16	)	$	(1	)

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As of September 30, 2015, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $4.0 million as an increase to gas cost and approximately $6.5 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels.  As of September 30, 2015, all of the Company’s commodity cash flow hedges settle by their terms before the end of the second quarter of 2018.

As of September 30, 2015, the Company expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $2.3 million as an increase to interest expense, assuming financial markets remain at their current levels.

Hedge Ineffectiveness

Ineffectiveness on interest rate hedges designated as cash flow hedges was insignificant during all periods presented.

Derivatives not designated as Hedging Instruments
	Loss Deferred in Regulatory Accounts							Gain Reclassified from Deferred Accounts into Income
Millions of dollars	2015			2014			Location	2015		2014
Three Months Ended September 30,
Interest rate contracts	$	(116	)	$	(35	)	Other income	—		$	5
Nine Months Ended September 30,
Interest rate contracts	$	(79	)	$	(220	)	Other income	$	5	$	60

As of September 30, 2015, the Company expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from derivatives not designated as hedges will include $0.6 million as an increase to interest expense.

Credit Risk Considerations

The Company limits credit risk in its commodity and interest rate derivatives activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. In this regard, the Company uses credit ratings provided by credit rating agencies and current market-based qualitative and quantitative data, as well as financial statements, to assess the financial health of counterparties. The Company uses standardized master agreements which may include collateral requirements. These master agreements permit the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements permit the secured party to demand the posting of cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with the Company's credit policies and due diligence. In addition, collateral agreements allow for the termination and liquidation of all positions in the event of a failure or inability to post collateral.

Certain of the Company’s derivative instruments contain contingent provisions that may require the Company to provide collateral upon the occurrence of specific events, primarily credit downgrades. As of September 30, 2015 and December 31, 2014, the Company had posted $148.4 million and $152.4 million, respectively, of collateral related to derivatives with contingent provisions that were in a net liability position. Collateral related to the positions expected to close in the next 12 months is recorded in Other Current Assets on the condensed consolidated balance sheets. Collateral related to noncurrent positions is recorded in Other within Deferred Debits and Other Assets on the condensed consolidated balance sheets. If all of the contingent features underlying these instruments had been fully triggered as of September 30, 2015 and December 31, 2014, the Company could have been required to post an additional $69.1 million and $129.8 million, respectively, of collateral with its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of September 30, 2015 and December 31, 2014 is $217.5 million and $282.2 million, respectively.

In addition, as of September 30, 2015 and December 31, 2014, the Company has collected no cash collateral related to interest rate derivatives with contingent provisions that are in a net asset position. If all the contingent features underlying these instruments had been fully triggered as of September 30, 2015 and December 31, 2014, the Company could request $2.8

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million and $- million, respectively, of cash collateral from its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net asset position as of September 30, 2015 and December 31, 2014 is $2.8 million and $- million, respectively. In addition, as of September 30, 2015, the Company could have called on letters of credit in the amount of $3.0 million related to $15.0 million in commodity derivatives that are in a net asset position, compared to letters of credit of $9.2 million related to derivatives of $20.0 million at December 31, 2014, if all the contingent features underlying these instruments had been fully triggered.

Information related to the Company's offsetting of derivative assets follows:

	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position				Net Amount
Millions of dollars						Financial Instruments			Cash Collateral Received
As of September 30, 2015
Interest rate contracts	$	6	—	$	6	$	(3	)	—	$	3
Energy management contracts	15		—	15		—			—	15
Total	$	21	—	$	21	$	(3	)	—	$	18
Balance sheet location	Other current assets			$	10
	Other deferred debits and other assets			11
	Total			$	21

As of December 31, 2014
Commodity contracts	$	1	—	$	1	—	—	$	1
Energy management contracts	20		—	20		—	—	20
Total	$	21	—	$	21	—	—	$	21
Balance sheet location	Other current assets			$	16
	Other deferred debits and other assets			5
	Total			$	21

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Information related to the Company's offsetting of derivative liabilities follows:

	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position						Net Amount
Millions of dollars						Financial Instruments			Cash Collateral Posted
As of September 30, 2015
Interest rate contracts	$	202	—	$	202	$	(3	)	$	(135	)	$	64
Commodity contracts	7		—	7		—			(6		)	1
Energy management contracts	14		—	14		—			(7		)	7
Total	$	223	—	$	223	$	(3	)	$	(148	)	$	72
Balance sheet location	Other current assets			$	3
	Derivative financial instruments			125
	Other deferred credits and other liabilities			95
	Total			$	223

As of December 31, 2014
Interest rate contracts	$	257	—	$	257	—	$	(131	)	$	126
Commodity contracts	12		—	12		—	(10		)	2
Energy management contracts	20		—	20		—	(11		)	9
Total	$	289	—	$	289	—	$	(152	)	$	137
Balance sheet location	Other current assets			$	6
	Derivative financial instruments			233
	Other deferred credits and other liabilities			50
	Total			$	289

7. FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

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

	As of September 30, 2015				As of December 31, 2014
Millions of dollars	Level 1		Level 2		Level 1		Level 2
Assets:
Available for sale securities	$	13	—		$	13	—
Interest rate contracts	—		$	6	—		—
Commodity contracts	—		—		1		—
Energy management contracts	—		15		—		$	20
Liabilities:
Interest rate contracts	—		202		—		257
Commodity contracts	1		6		1		11
Energy management contracts	2		15		5		18

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

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

	September 30, 2015				December 31, 2014
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	6,034.3	$	6,623.3	$	5,697.2	$	6,592.1

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

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

8. EMPLOYEE BENEFIT PLANS

Components of net periodic benefit cost recorded by the Company were as follows: 

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2015			2014			2015		2014
Three months ended September 30,
Service cost	$	6.6		$	5.0		$	1.2	$	0.9
Interest cost	9.6			9.9			2.8		2.8
Expected return on assets	(15.5		)	(16.4		)	—		—
Prior service cost amortization	1.0			1.1			0.1		0.1
Amortization of actuarial losses (gains)	3.2			0.9			0.4		(0.2		)
Net periodic benefit cost	$	4.9		$	0.5		$	4.5	$	3.6

Nine months ended September 30,
Service cost	$	18.1		$	15.0		$	4.0	$	3.4
Interest cost	28.7			30.3			8.6		9.0
Expected return on assets	(46.5		)	(50.0		)	—		—
Prior service cost amortization	3.0			3.1			0.3		0.3
Amortization of actuarial losses	10.2			3.5			1.5		—
Net periodic benefit cost	$	13.5		$	1.9		$	14.4	$	12.7

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

9. COMMITMENTS AND CONTINGENCIES

Nuclear Insurance

Under Price-Anderson, SCE&G (for itself and on behalf of Santee Cooper, a one-third owner of Summer Station Unit 1) maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at SCE&G's nuclear power plant. Price-Anderson provides funds up to $12.9 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $375 million by ANI with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. Each reactor licensee is currently liable for up to $127.3 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $18.9 million of the liability per reactor would be assessed per year. SCE&G’s maximum

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assessment, based on its two-thirds ownership of Summer Station Unit 1, would be $84.8 million per incident, but not more than $12.6 million per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years.

SCE&G currently maintains insurance policies (for itself and on behalf of Santee Cooper) with NEIL. The policies provide coverage to Summer Station Unit 1 for property damage and outage costs up to $2.75 billion resulting from an event of nuclear origin. In addition, a builder's risk insurance policy has been purchased from NEIL for the construction of the New Units. This policy provides the owners of the New Units up to $500 million in limits of accidental property damage occurring during construction. The NEIL policies, in the aggregate, are subject to a maximum loss of $2.75 billion for any single loss occurrence. All of the NEIL policies permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $45.9 million.

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

New Nuclear Construction

In 2008, SCE&G, on behalf of itself and as agent for Santee Cooper, contracted with the Consortium for the design and construction of the New Units at the site of Summer Station.  

SCE&G's current ownership share in the New Units is 55%. As discussed below, under an agreement signed in January 2014 (and subject to customary closing conditions, including necessary regulatory approvals), SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper.

EPC Contract and BLRA Matters

The construction of the New Units and SCE&G’s related recovery of financing costs through rates is subject to review and approval by the SCPSC as provided for in the BLRA. Under the BLRA, the SCPSC has approved, among other things, a milestone schedule and a capital costs estimates schedule for the New Units. This approval constitutes a final and binding determination that the New Units are used and useful for utility purposes, and that the capital costs associated with the New Units are prudent utility costs and expenses and are properly included in rates, so long as the New Units are constructed or are being constructed within the parameters of the approved milestone schedule, including specified schedule contingencies, and the approved capital costs estimates schedule. Subject to the same conditions, the BLRA provides that SCE&G may apply to the SCPSC annually for an order to recover through revised rates SCE&G’s weighted average cost of capital applied to all or part of the outstanding balance of construction work in progress concerning the New Units. Such annual rate changes are described in Note 2. As of September 30, 2015, SCE&G’s investment in the New Units, including related transmission, totaled $3.3 billion, for which the financing costs on $2.4 billion have been reflected in rates under the BLRA.

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

Since the settlement of delay-related claims in 2012, the Consortium has continued to experience delays in the schedule, including those related to fabrication and delivery of sub-modules for the New Units. The fabrication and delivery of sub-modules have been and remain focus areas of the Consortium. Shield building panels are considered critical path items for both New Units, and the current schedule for production of such panels will require mitigation to support the updated substantial completion dates (see below).

During the fourth quarter of 2013, the Consortium began a full re-baselining of the Unit 2 and Unit 3 construction schedules to incorporate a more detailed evaluation of the engineering and procurement activities necessary to accomplish the schedules and to provide a detailed reassessment of the impact of the revised Unit 2 and Unit 3 schedules on engineering and

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design resource allocations, procurement, construction work crew efficiencies, and other items. The result was a revised, fully integrated project schedule with timing of specific construction activities (Revised, Fully-Integrated Construction Schedule) along with related cost information.

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

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

On October 27, 2015, SCE&G, Santee Cooper and the Consortium reached a settlement regarding the above mentioned disputes, and the EPC Contract was amended. The October 2015 Amendment will become effective upon the consummation of the acquisition by WEC of the stock of Stone & Webster from CB&I, and will become null and void in the event such acquisition is not consummated by March 31, 2016. Following that acquisition, Stone & Webster will continue to be a member of the Consortium as a subsidiary of WEC rather than CB&I, and WEC intends to engage Fluor Corporation or its affiliate(s) as a subcontracted construction manager.

Among other things, upon effectiveness, the October 2015 Amendment would (i) resolve by settlement and release substantially all outstanding disputes between SCE&G and the Consortium, in exchange for (a) an additional cost to be paid by SCE&G and Santee Cooper of $300 million (SCE&G’s 55% portion being $165 million) and an increase in the fixed component of the contract price by that amount, and (b) a credit to SCE&G and Santee Cooper of $50 million (SCE&G’s 55% portion being approximately $27 million) to be applied to the target component of the contract price, (ii) revise the guaranteed substantial completion dates of Units 2 and 3 to August 31, 2019 and 2020, respectively, (iii) revise the delay-related liquidated damages computation requirements, including those related to the eligibility of the New Units to earn Internal Revenue Code Section 45J production tax credits (see also below), and cap those aggregate liquidated damages at $463 million per New Unit (SCE&G’s 55% portion being approximately $255 million per New Unit), (iv) provide for payment to the Consortium of a completion bonus of $275 million per New Unit (SCE&G’s 55% portion being approximately $151 million per New Unit) for each New Unit placed in service by the deadline to qualify for production tax credits, (v) provide for the development of a revised construction milestone payment schedule, with SCE&G and Santee Cooper making monthly payments of $100 million (SCE&G’s 55% portion being $55 million) for each of the first five months following effectiveness, followed by payments made based on milestones achieved, and (vi) provide that SCE&G and Santee Cooper waive and cancel the CB&I parent company guaranty with respect to the project. The payment obligations under the EPC Contract are joint and several obligations of WEC and Stone & Webster, and the October 2015 Amendment provides for Toshiba Corporation, WEC’s parent company, to reaffirm its guaranty of WEC’s payment obligations. Under the October 2015 Amendment, SCE&G’s total estimated project costs will increase by approximately $286 million over the $6.8 billion approved by the SCPSC in September 2015, and will bring its total estimated gross construction cost of the project (including escalation and AFC) to approximately $7.1 billion.

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

Finally, upon effectiveness, the October 2015 Amendment would provide SCE&G and Santee Cooper an irrevocable option, until November 1, 2016 and subject to regulatory approvals, to further amend the EPC Contract to fix the total amount

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to be paid to the Consortium for its entire scope of work on the project (excluding a limited amount of work within the time and materials component of the contract price) after June 30, 2015 at $6.082 billion (SCE&G’s 55% portion being approximately $3.345 billion). This total amount to be paid would be subject to adjustment for amounts paid since June 30, 2015. Were this fixed price option to be exercised, the aggregate delay-related liquidated damages amount referred to in (iii) above would be capped at $338 million per unit (SCE&G’s 55% portion being approximately $186 million per unit), and the completion bonus amounts referred to in (iv) above would be $150 million per New Unit (SCE&G’s 55% portion being approximately $83 million per New Unit). The exercise of this fixed price option would result in SCE&G’s total estimated project costs increasing by approximately $774 million over the $6.8 billion approved by the SCPSC in September 2015, and would bring its total estimated gross construction cost (including escalation and AFC) of the project to approximately $7.6 billion.

Resolution of the disputes as described in (i) above, or in the case of the exercise of the fixed price option, would result in estimated project costs above the amounts approved by the SCPSC; however, the guaranteed substantial completion dates fall within the SCPSC approved 18-month contingency periods. SCE&G expects to hold an allowable ex parte communication briefing with the SCPSC on November 19, 2015 and, following an evaluation as to whether to exercise the fixed price option, expects to file a petition, as provided under the BLRA, for an update to the project’s estimated capital cost schedule which would incorporate the impact of this October 2015 Amendment.

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

Santee Cooper Matters

As noted above, SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper. Under the terms of this agreement, SCE&G will acquire a 1% ownership interest in the New Units at the commercial operation date of Unit 2, an additional 2% ownership interest no later than the first anniversary of such commercial operation date, and the final 2% no later than the second anniversary of such commercial operation date. SCE&G has agreed to pay an amount equal to Santee Cooper's actual cost, including its cost of financing, of the percentage conveyed as of the date of each conveyance. In addition, the agreement provides that Santee Cooper will not transfer any of its remaining interest in the New Units to third parties until the New Units are complete. This transaction will not affect the payment obligations between the parties during construction for the New Units, nor is it anticipated that the payments for the additional ownership interest would be reflected in a revised rates filing under the BLRA. Based on the current milestone schedule and capital costs schedule approved by the SCPSC in September 2015 and without considering the October 2015 Amendment discussed above, SCE&G’s estimated cost would be approximately $750 million for the additional 5% interest being acquired from Santee Cooper.

Nuclear Production Tax Credits

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

Other Project Matters

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

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Environmental

The Company's operations are subject to extensive regulation by various federal and state authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes. Applicable statutes and rules include the CAA, CWA, Nuclear Waste Act and CERCLA, among others. In many cases, regulations proposed by such authorities could have a significant impact on the Company's financial condition, results of operations and cash flows. In addition, the Company often cannot predict what conditions or requirements will be imposed by regulatory or legislative proposals. To the extent that compliance with environmental regulations or legislation results in capital expenditures or operating costs, the Company expects to recover such expenditures and costs through existing ratemaking provisions.

From a regulatory perspective, SCANA, SCE&G and GENCO continually monitor and evaluate their current and projected emission levels and strive to comply with all state and federal regulations regarding those emissions. SCE&G and GENCO participate in the sulfur dioxide and nitrogen oxide emission allowance programs with respect to coal plant emissions and also have constructed additional pollution control equipment at several larger coal-fired electric generating plants. Further, SCE&G is engaged in construction activities of the New Units which are expected to reduce GHG emission levels significantly once they are completed and dispatched by potentially displacing some of the current coal-fired generation sources. These actions are expected to address many of the rules and regulations discussed herein.

On August 3, 2015, the EPA issued a revised carbon standard for new power plants by re-proposing NSPS under the CAA for emissions of carbon dioxide from newly constructed fossil fuel-fired units. The final rule requires all new coal-fired power plants to meet a carbon emission rate of 1,400 pounds carbon dioxide per MWh and new natural gas units to meet 1,000 pounds carbon dioxide per MWh. While most new natural gas plants will not be required to include any new technologies, no new coal-fired plants could be constructed without partial carbon capture and sequestration capabilities. The Company is evaluating the final rule, but does not plan to construct new coal-fired units in the foreseeable future. In addition, on August 3, 2015, the EPA issued its final rule on emission guidelines for states to follow in developing plans to address GHG emissions from existing units. The rule includes state-specific goals for reducing national carbon dioxide emissions by 32% from 2005 levels by 2030. The rule also provides for nuclear reactors under construction, such as the New Units, to count towards compliance and establishes a phased-in compliance approach beginning in 2022. The Company is currently evaluating the rule and expects any costs incurred to comply with such rule to be recoverable through rates.

In July 2011, the EPA issued the CSAPR to reduce emissions of sulfur dioxide and nitrogen oxide from power plants in the eastern half of the United States. A series of court actions stayed this rule until October 23, 2014, when the Court of Appeals granted a motion to lift the stay. On December 3, 2014, the EPA published an interim final rule that aligns the dates in the CSAPR text with the revised court-ordered schedule, thus delaying the implementation dates to 2015 for Phase 1 and to 2017 for Phase 2. The CSAPR replaces the CAIR and requires a total of 28 states to reduce annual sulfur dioxide emissions and annual or ozone season nitrogen oxide emissions to assist in attaining the ozone and fine particle NAAQS. The rule establishes an emissions cap for sulfur dioxide and nitrogen oxide and limits the trading for emission allowances by separating affected states into two groups with no trading between the groups. On July 28, 2015, the Court of Appeals held that Phase 2 emissions budgets for certain states, including South Carolina, required reductions in emissions beyond the point necessary to achieve downwind attainment and were, therefore, invalid. The Court of Appeals remanded CSAPR, without vacating the rule, to the EPA for further consideration. The opinion of the Court of Appeals has no immediate impact on SCE&G and GENCO or their generation operations. Air quality control installations that SCE&G and GENCO have already completed have positioned them to comply with the existing allowances set by the CSAPR. Any cost incurred to comply with CSAPR are expected to be recoverable through rates.

In April 2012, the EPA's MATS rule containing new standards for mercury and other specified air pollutants became effective. The rule provides up to four years for generating facilities to meet the standards, and the Company's evaluation of the rule is ongoing. The Company's decision to retire certain coal-fired units (see Note 2) and its project to build the New Units along with other actions are expected to result in the Company's compliance with MATS.

On November 19, 2014, the EPA finalized its reconsideration of certain provisions applicable during startup and shutdown of generating facilities. SCE&G and GENCO have received a one year extension (until April 2016) to comply with MATS at Cope, McMeekin, Wateree and Williams Stations. These extensions will allow time to convert McMeekin Station to burn natural gas and to install additional pollution control devices at the other plants that will enhance the control of certain MATS-regulated pollutants. On June 29, 2015, the U.S. Supreme Court ruled that the EPA unreasonably failed to consider costs in its decision to regulate, and remanded a case challenging the regulation on that basis to the Court of Appeals. The ruling, however, is not expected to have an impact on SCE&G or GENCO due to the aforementioned retirements and conversions.

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

The CWA Section 316(b) Existing Facilities Rule became effective in October 2014. This rule establishes national requirements for the location, design, construction and capacity of cooling water intake structures at existing facilities that reflect the best technology available for minimizing the adverse environmental impacts of impingement and entrainment. SCE&G and GENCO are conducting studies and implementing plans to ensure compliance with this rule. In addition, Congress is expected to consider further amendments to the CWA. Such legislation may include toxicity-based standards as well as limitations to mixing zones.

On April 17, 2015, the EPA's final rule for CCR was published in the Federal Register and became effective in the fourth quarter of 2015. This rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act and imposes certain requirements on ash storage ponds and other CCR management facilities at SCE&G's and GENCO's coal-fired generating facilities. Although the full effects of this rule are still being evaluated, SCE&G and GENCO have already closed or have begun the process of closure of all of their ash storage ponds and have previously recognized AROs for such ash storage ponds under existing requirements. The Company does not expect the incremental compliance costs associated with this rule to be significant and expects to recover such costs in future rates.

The Nuclear Waste Act required that the United States government accept and permanently dispose of high-level radioactive waste and spent nuclear fuel by January 31, 1998, and it imposed on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. SCE&G entered into a Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with the DOE in 1983. As of September 30, 2015, the federal government has not accepted any spent fuel from Summer Station Unit 1, and it remains unclear when the repository may become available. SCE&G has on-site spent nuclear fuel storage capability in its existing fuel pool until at least 2017 and is constructing a dry cask storage facility to accommodate the spent nuclear fuel output for the life of Summer Station Unit 1. SCE&G may evaluate other technology as it becomes available.

The provisions of CERCLA authorize the EPA to require the clean-up of hazardous waste sites. The states of South Carolina and North Carolina have similar laws. The Company maintains an environmental assessment program to identify and evaluate current and former operations sites that could require clean-up. In addition, regulators from the EPA and other federal or state agencies periodically notify the Company that it may be required to perform or participate in the investigation and remediation of a hazardous waste site. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures may differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Such amounts are recorded in regulatory assets and amortized, with recovery provided through rates.

SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC and the EPA. SCE&G anticipates that major remediation activities at all these sites will continue at least through 2017 and will cost an additional $19.0 million, which is accrued in Other within Deferred Credits and Other Liabilities on the condensed consolidated balance sheet. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates. At September 30, 2015, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $34.7 million and are included in regulatory assets.

Asset Retirement Obligations

The Company recognizes a liability for the present value of an ARO when incurred if the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional ARO is factored into the measurement of the liability when sufficient information exists, but such uncertainty is not a basis upon which to avoid liability recognition.

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The legal obligations associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation relate primarily to the Company’s utility operations.  As of September 30, 2015 and December 31, 2014, the Company has recorded AROs of approximately $174 million and $201 million, respectively, for nuclear plant decommissioning and AROs of approximately $315 million and $362 million, respectively, for other conditional obligations primarily related to generation, transmission and distribution properties, including gas pipelines. All of the amounts recorded are based upon estimates which are subject to varying degrees of imprecision, particularly since such payments will be made many years in the future.

A reconciliation of the beginning and ending carrying amount of asset retirement obligations is as follows:

Millions of dollars	September 30, 2015			December 31, 2014
Beginning balance	$	563		$	576
Liabilities incurred	—			3
Liabilities settled	(15		)	(6		)
Accretion expense	20			26
Revisions in estimated cash flows	(79		)	(36		)
Ending balance	$	489		$	563

Revisions in estimated cash flows during 2015 primarily relate to changes in the expected timing of settlement of AROs in light of changes in the estimated useful lives of certain electric utility properties identified as part of a customary depreciation study.

10. SEGMENT OF BUSINESS INFORMATION

The Company’s reportable segments are listed in the following table. The Company uses operating income to measure profitability for its regulated operations; therefore, net income is not allocated to the Electric Operations and Gas Distribution segments. The Company uses net income to measure profitability for its Retail Gas Marketing and Energy Marketing segments.  Gas Distribution is comprised of the local distribution operations of SCE&G and PSNC Energy which meet the criteria for aggregation. All Other includes the parent company, a services company and other nonreportable segments that were insignificant for all periods presented. In addition, All Other includes gains from the sales of CGT and SCI (see Note 11) and their operating results and assets prior to their sale in the first quarter of 2015. CGT and SCI were nonreportable segments during all periods presented. For the period ended September 30, 2015, operating income and net income for All Other include $235 million and $201 million, respectively, related to the sales of CGT and SCI. External revenue and intersegment revenue for All Other related to CGT and SCI were not significant during any period presented.

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

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

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Three Months Ended September 30, 2014
Electric Operations	$	739		$	1		$	275		n/a
Gas Distribution	127			—			(6		)	n/a
Retail Gas Marketing	68			—			n/a			$	(3	)
Energy Marketing	182			47			n/a			(2		)
All Other	9			103			7			(5		)
Adjustments/Eliminations	(4		)	(151		)	(7		)	154
Consolidated Total	$	1,121		$	—		$	269		$	144

Nine Months Ended September 30, 2014
Electric Operations	$	2,027		$	5		$	616	n/a
Gas Distribution	728			—			98		n/a
Retail Gas Marketing	367			—			n/a		$	16
Energy Marketing	602			154			n/a		5
All Other	27			317			21		(3		)
Adjustments/Eliminations	(15		)	(476		)	37		415
Consolidated Total	$	3,736		$	—		$	772	$	433

	September 30,		December 31,
Segment Assets	2015		2014
Electric Operations	$	10,531	$	10,182
Gas Distribution	2,498		2,487
Retail Gas Marketing	107		140
Energy Marketing	102		150
All Other	998		1,474
Adjustments/Eliminations	2,270		2,419
Consolidated Total	$	16,506	$	16,852

11.    DISPOSITIONS

In December 2014, SCANA entered into definitive agreements to sell CGT and SCI. CGT is an interstate natural gas pipeline regulated by FERC that transports natural gas in South Carolina and southeastern Georgia, and it was sold to Dominion Resources, Inc. SCI provides fiber optic communications and other services and builds, manages and leases communications towers in several southeastern states, and it was sold to a subsidiary of Spirit Communications. These sales closed in the first quarter of 2015 and resulted in recognition of pre-tax gains totaling approximately $342 million. As further described in Note 1, the pre-tax gain from the sale of CGT is included within Operating Income and the pre-tax gain from the sale of SCI is included within Other Income (Expense) on the condensed consolidated income statement.

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

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The carrying values of the assets and liabilities classified as held for sale in the consolidated balance sheet as of December 31, 2014, were as follows:

Millions of dollars	CGT		SCI		Total
Assets Held for Sale
Utility Plant, Net	$	288.4	—		$	288.4
Nonutility Property and Investments, Net	0.6		$	40.1	40.7
Current Assets	6.5		3.9		10.4
Deferred Debits and Other Assets	0.9		0.2		1.1
Total Assets Held for Sale	$	296.4	$	44.2	$	340.6
Liabilities Held for Sale
Current Liabilities	$	3.5	$	2.2	$	5.7
Deferred Credits and Other Liabilities	42.9		3.1		46.0
Total Liabilities Held for Sale	$	46.4	$	5.3	$	51.7

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

OF OPERATIONS

SCANA CORPORATION

The following discussion should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations appearing in SCANA’s Annual Report on Form 10-K for the year ended December 31, 2014.

RESULTS OF OPERATIONS

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2015

AS COMPARED TO THE CORRESPONDING PERIODS IN 2014

Earnings Per Share

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

	Third Quarter				Year to Date
	2015		2014		2015		2014
GAAP earnings per share	$	1.04	$	1.01	$	4.53	$	3.06
Deduct:
Gain on sale of CGT	—		—		0.95		—
Gain on sale of SCI	—		—		0.46		—
SCE&G Electric - effect of abnormal weather	0.11		0.07		0.22		0.23
GAAP-adjusted weather-normalized net earnings per share	$	0.93	$	0.94	$	2.90	$	2.83

Third Quarter

Third quarter earnings per share on a GAAP basis increased due to higher electric operations margin and lower depreciation expense. These increases were partially offset by lower gas margins, higher operation and maintenance expenses, higher property taxes, higher interest cost, higher income taxes and dilution from additional shares outstanding, as further discussed below.

Year to Date

Year to date earnings per share on a GAAP basis increased due to the sale of CGT and SCI in the first quarter of 2015, higher electric operations margin and lower depreciation expense. These increases were partially offset by lower gas margins, higher operation and maintenance expenses, higher property taxes, higher interest cost, higher income taxes and dilution from additional shares outstanding, as further discussed below.

Discussion of above adjustments:

The sales of CGT and SCI were closed in the first quarter of 2015. These subsidiaries operated principally in wholesale markets, whereas the Company's primary focus is the delivery of energy-related products and services to retail markets. Therefore, CGT and SCI were not a part of the Company's core business. See Note 11 to the condensed consolidated financial statements.

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SCE&G estimates the effects of abnormal weather on its electric business by comparing actual temperatures in its service territory to a historical average. The result is used in developing an estimate of electric margin revenue, using average margin rates, attributable to the effects of abnormal weather.

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

Dividends Declared

SCANA’s Board of Directors has declared the following dividends on common stock during 2015:

Declaration Date	Dividend Per Share	Record Date	Payment Date
February 20, 2015	$0.545	March 10, 2015	April 1, 2015
April 30, 2015	$0.545	June 10, 2015	July 1, 2015
July 30, 2015	$0.545	September 10, 2015	October 1, 2015
October 29, 2015	$0.545	December 10, 2015	January 1, 2016

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

Electric Operations

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

	Third Quarter						Year to Date
Millions of dollars	2015		Change		2014		2015		Change		2014
Operating revenues	$	743.6	0.4	%	$	740.4	$	2,012.7	(1.0	)%	$	2,032.7
Less:  Fuel used in generation	186.7		(12.5	)%	213.3		524.8		(18.0	)%	639.9
Purchased power	14.0		6.9	%	13.1		38.3		(29.6	)%	54.4
Margin	542.9		5.6	%	514.0		1,449.6		8.3	%	1,338.4
Other operation and maintenance expenses	126.3		8.8	%	116.1		367.3		3.1	%	356.4
Depreciation and amortization	55.2		(26.5	)%	75.1		207.5		(11.2	)%	233.8
Other taxes	48.6		1.5	%	47.9		146.6		3.0	%	142.3
Operating Income	$	312.8	13.8	%	$	274.9	$	728.2	20.2	%	$	605.9

Third Quarter

Margin increased due to base rate increases under the BLRA of $19.8 million, weather of $10.7 million and residential and commercial customer growth of $6.8 million. These increases were partially offset by lower industrial margins of $2.4 million. Margin also decreased due to downward adjustments of $14.5 million in 2015, compared to $4.4 million in 2014, pursuant to orders of the SCPSC, related to fuel cost recovery and SCE&G’s DSM Programs. These adjustments were fully offset by the recognition, within other income, of gains realized upon the late 2013 settlement of certain interest rate contracts and lower depreciation expense upon the adoption and implementation of revised depreciation rates as a result of an updated depreciation study. Operations and maintenance expenses increased due to higher labor costs of $7.4 million, primarily due to higher incentive compensation costs, incremental storm expenses of $1.4 million and due to the amortization of $1.5 million of DSM Programs cost. Depreciation and amortization decreased by $21.7 million in 2015 due to the implementation of the above mentioned revised depreciation rates, $14.5 million of which was offset by downward revenue adjustments. This decrease in depreciation expense was partially offset by increases associated with net plant additions. Other taxes increased due to net plant additions.

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Year to Date

Margin increased due to downward adjustments of $64.6 million in 2014, compared to downward adjustments of $19.7 million in 2015, pursuant to orders of the SCPSC, related to fuel cost recovery and SCE&G’s DSM Programs. These adjustments were fully offset by the recognition, within other income, of gains realized upon the late 2013 settlement of certain interest rate contracts, lower depreciation expense upon the adoption and implementation of revised depreciation rates as a result of an updated depreciation study and the application, as a reduction to operation and maintenance expenses, of a portion of SCE&G’s storm damage reserve. Margin also increased due to base rate increases under the BLRA of $51.3 million and residential and commercial customer growth of $15.9 million. These increases were partially offset by lower industrial margins of $8.9 million and lower collections under SCE&G’s rate rider for pension costs of $3.0 million. Operations and maintenance expenses increased due to higher labor costs of $2.6 million, primarily due to higher incentive compensation costs, partially offset by lower pension costs as a result of lower rate rider collections, the application of $5.0 million in 2014 of SCE&G’s storm damage reserve to offset downward revenue adjustments related to its DSM Programs and the amortization of $2.9 million of DSM Programs cost. Depreciation and amortization decreased by $21.7 million in 2015 due to the implementation of the above mentioned revised depreciation rates, $14.5 million of which was offset by downward revenue adjustments. This decrease in depreciation expense was partially offset by increases associated with net plant additions. Other taxes increased due to net plant additions.

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

	Third Quarter				Year to Date
Classification	2015	Change		2014	2015	Change		2014
Residential	2,426	4.8	%	2,315	6,425	0.9	%	6,370
Commercial	2,143	2.0	%	2,100	5,754	1.4	%	5,676
Industrial	1,660	(0.5	)%	1,668	4,726	1.4	%	4,662
Other	165	(2.9	)%	170	458	(0.2	)%	459
Total Retail Sales	6,394	2.3	%	6,253	17,363	1.1	%	17,167
Wholesale	266	3.1	%	258	749	1.6	%	737
Total Sales	6,660	2.3	%	6,511	18,112	1.2	%	17,904

Third Quarter

Retail sales volume increased primarily due to customer growth and the effects of weather.

Year to Date

Retail sales volume increased primarily due to customer growth.

Gas Distribution

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

	Third Quarter								Year to Date
Millions of dollars	2015			Change		2014			2015		Change		2014
Operating revenues	$	112.1		(12.4	)%	$	127.9		$	610.7	(16.3	)%	$	729.5
Less:  Gas purchased for resale	53.9			(22.3	)%	69.4			317.9		(27.4	)%	437.6
Margin	58.2			(0.5	)%	58.5			292.8		0.3	%	291.9
Other operation and maintenance expenses	42.6			15.8	%	36.8			119.4		5.3	%	113.4
Depreciation and amortization	19.4			6.6	%	18.2			57.7		6.9	%	54.0
Other taxes	9.3			6.9	%	8.7			28.0		6.9	%	26.2
Operating Income (Loss)	$	(13.1	)	151.9	%	$	(5.2	)	$	87.7	(10.8	)%	$	98.3

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Third Quarter

Margin decreased primarily due to a SCPSC-approved decrease in base rates under the RSA which became effective in November 2014. Operation and maintenance expenses increased primarily due to higher labor costs, primarily due to higher incentive compensation costs. Depreciation and amortization and other taxes increased due to net plant additions.

Year to Date

Margin increased primarily due to residential and commercial customer growth and an industrial customer shift from interruptible to firm service, partially offset by a SCPSC-approved decrease in base rates under the RSA which became effective in November 2014 and decreases associated with franchise fee revenue. Operation and maintenance expenses increased primarily due to higher labor costs. Depreciation and amortization and other taxes increased due to net plant additions.

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

	Third Quarter				Year to Date
Classification (in thousands)	2015	Change		2014	2015	Change		2014
Residential	2,069	(3.7	)%	2,149	29,786	(4.4	)%	31,165
Commercial	4,329	(1.5	)%	4,396	21,233	(2.6	)%	21,808
Industrial	4,786	0.8	%	4,749	15,024	(0.7	)%	15,128
Transportation	13,610	20.0	%	11,341	36,101	9.7	%	32,912
Total	24,794	9.5	%	22,635	102,144	1.1	%	101,013

Third Quarter

Commercial interruptible volumes at SCE&G decreased due to lower average usage. Residential and commercial firm sales volumes decreased due to lower average usage, partially offset by customer growth. Transportation at PSNC Energy increased due to industrial expansion and a slight improvement in the economy.

Year to Date

Residential and commercial firm sales volumes decreased due to the effects of weather and lower average usage, partially offset by customer growth. Commercial and industrial interruptible volumes at SCE&G decreased due to curtailments and lower average use. Industrial and transportation volumes at PSNC Energy increased due to industrial expansion, improvement in the economy, and lower curtailment activity. Transportation volumes at SCE&G increased due to customers shifting to transportation only service.

Retail Gas Marketing

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

	Third Quarter								Year to Date
Millions of dollars	2015			Change		2014			2015		Change		2014
Operating revenues	$	67.9		(0.7	)%	$	68.4		$	344.0	(6.4	)%	$	367.4
Net income (loss)	(3.9		)	39.3	%	(2.8		)	17.6		7.3	%	16.4

Third Quarter

Operating revenues decreased as natural gas prices declined, and net loss increased primarily due to higher operating expenses.

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Year to Date

Operating revenues decreased as natural gas prices declined. Net income increased due to lower commodity costs and lower bad debt expense related primarily to lower revenues.

Energy Marketing

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

	Third Quarter								Year to Date
Millions of dollars	2015			Change		2014			2015		Change		2014
Operating revenues	$	180.4		(21.2	)%	$	228.8		$	562.5	(25.6	)%	$	756.1
Net income (loss)	(0.6		)	(76.9	)%	(2.6		)	8.1		58.8	%	5.1

Third Quarter and Year to Date

Operating revenues decreased primarily due to lower market prices. Net income increased (loss decreased) primarily due to lower transportation costs. 

Other Operating Expenses

Other operating expenses were as follows:

	Third Quarter						Year to Date
Millions of dollars	2015		Change		2014		2015		Change		2014
Other operation and maintenance	$	181.8	7.4	%	$	169.2	$	527.0	0.8	%	$	522.9
Depreciation and amortization	75.0		(21.8	)%	95.9		267.3		(6.6	)%	286.1
Other taxes	58.3		0.2	%	58.2		176.3		1.4	%	173.8

Changes in other operating expenses are largely attributable to the electric operations and gas distribution segments and are addressed in those discussions. In addition, for the third quarter and year to date, other operation and maintenance expense decreased by $6.1 million and $16.1 million, depreciation and amortization decreased by $2.2 million and $5.7 million and other taxes decreased by $1.4 million and $3.6 million, respectively, due to the sale of CGT in early 2015.

Other Income (Expense)

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

	Third Quarter								Year to Date
Millions of dollars	2015			Change		2014			2015			Change		2014
Other income	$	18.5		3.4	%	$	17.9		$	55.6		(46.0	)%	$	103.0
Other expense	(16.4		)	37.8	%	(11.9		)	(43.5		)	12.7	%	(38.6		)
AFC - equity funds	8.2			(24.1	)%	10.8			19.9			(22.3	)%	25.6

Third Quarter

Other income decreased due primarily to the recognition of $4.4 million of gains in 2014 realized upon the settlement of certain interest rate contracts previously recorded as regulatory liabilities pursuant to the SCPSC orders previously discussed. Such gain recognition was fully offset by downward adjustments to revenues reflected within electric margin and

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had no effect on net income (see electric margin discussion). Other income decreased by $5.4 million and other expenses decreased by $3.3 million due to the sale of SCI. AFC decreased due to lower AFC rates.

Year to Date

Other income decreased due primarily to the recognition of $59.6 million of gains in 2014, compared to $5.2 million in 2015, realized upon the settlement of certain interest rate contracts previously recorded as regulatory liabilities pursuant to the SCPSC orders previously discussed. Such gain recognition was fully offset by downward adjustments to revenues reflected within electric margin and had no effect on net income (see electric margin discussion). Other income decreased by $12.6 million and other expenses decreased by $7.6 million due to the sale of SCI. AFC decreased due to lower AFC rates.

Interest Expense

     Interest charges increased primarily due to increased borrowings.

Income Taxes

Income taxes for the three and nine months ended September 30, 2015 were higher than the same periods in 2014 primarily due to higher income before taxes. Year to date income before taxes was higher in 2015 primarily due to the sales of CGT and SCI, and the year to date effective tax rate for 2015 was higher than the rate for 2014 primarily due to higher income before taxes and tax items directly associated with the sales of CGT and SCI.

LIQUIDITY AND CAPITAL RESOURCES

The Company anticipates that its cash obligations will be met through internally generated funds and additional short- and long-term borrowings. The Company expects that, barring a future impairment of the capital markets, it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future, including the cash requirements for nuclear construction and refinancing maturing long-term debt. The Company’s ratio of earnings to fixed charges for the nine and 12 months ended September 30, 2015 was 5.00 and 4.45, respectively.

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

At September 30, 2015, the Company had net available liquidity of approximately $1.6 billion, comprised of cash on hand and available amounts under lines of credit. The credit agreements total an aggregate of $1.8 billion, of which $200 million is scheduled to expire in October 2016 and the remainder is scheduled to expire in October 2019. The Company regularly monitors the commercial paper and short-term credit markets to optimize the timing of repayment of outstanding balances on its draws, if any, from the credit facilities. The Company’s long-term debt portfolio has a weighted average maturity of approximately 20 years at a weighted average effective interest rate of 5.8%.  All of the long-term debt bears fixed interest rates or is swapped to fixed. To further preserve liquidity, the Company rigorously reviews its projected capital expenditures and operating costs and adjusts them where possible without impacting safety, reliability, and core customer service.

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

On January 29, 2015, SCANA entered into an unsecured, three-month credit agreement in the amount of $150 million. SCANA entered this agreement to ensure sufficient liquidity was available to redeem its junior subordinated notes on February 2, 2015. No borrowings were made under this agreement, and it expired according to its terms on February 6, 2015.

On February 2, 2015, SCANA redeemed prior to maturity $150 million of its 7.70% junior subordinated notes at their face value.

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In May 2015, SCE&G issued $500 million of 5.1% first mortgage bonds due September 1, 2065. Proceeds from this sale were used to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes.

SCANA issued approximately $14 million of common stock during January 2015 through various compensation and dividend reinvestment plans, after which the common stock needs of such plans have been met through open-market purchases.

SCE&G's current preliminary estimates of its capital expenditures for new nuclear construction (including transmission) for 2015 through 2017, which are subject to continuing review and adjustment, are $752 million in 2015, $1,032 million in 2016, and $959 million in 2017.

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

OTHER MATTERS

As Georgia's regulated provider, SCANA Energy provides service to low-income customers and customers unable to obtain or maintain natural gas service from other marketers at rates approved by the GPSC, and SCANA Energy receives funding from the Universal Service Fund to offset some of the bad debt associated with the low-income group. SCANA Energy's term as the regulated provider is scheduled to end on August 31, 2017.

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

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

For further discussion of changes in long-term debt and interest rate derivatives, including changes in the Company's market risk exposures relative to interest rate risk, see ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – LIQUIDITY AND CAPITAL RESOURCES and also Notes 2, 4, 6 and 7 of the 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 condensed consolidated financial statements. The following tables provide information about the Company’s financial instruments that are sensitive to changes in natural gas prices.  Weighted average settlement prices are per 10,000 MMBTU. Fair value represents quoted market prices for these or similar instruments.

	Expected Maturity				Expected Maturity
Futures - Long	2015	2016	2017	Options Purchased Call - Long	2015	2016
Settlement Price (a)	2.62	2.81	3.05	Strike Price (a)	3.68	3.64
Contract Amount (b)	6.8	13.3	1.0	Contract Amount (b)	13.3	22.7
Fair Value (b)	5.4	11.7	1.0	Fair Value (b)	—	0.5
Futures - Short	2015	2016
Settlement Price (a)	—	2.83
Contract Amount (b)	—	1.3
Fair Value (b)	—	1.2
(a)  Weighted average, in dollars
(b)  Millions of dollars

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	Expected Maturity
Swaps	2015	2016	2017	2018
Commodity Swaps:
Pay fixed/receive variable (b)	23.4	51.8	7.3	3.7
Average pay rate (a)	3.4295	3.4853	4.0251	4.1974
Average received rate (a)	2.6239	2.8108	3.0169	3.0498
Fair value (b)	17.9	41.8	5.5	2.7
Pay variable/receive fixed (b)	9.3	25.1	5.3	2.6
Average pay rate (a)	2.6155	2.8063	3.0133	3.0485
Average received rate (a)	3.6083	3.6926	4.0385	4.2471
Fair value (b)	12.8	33.1	7.1	3.6
Basis Swaps:
Pay variable/receive variable (b)	1.7	0.9	0.8	—
Average pay rate (a)	2.6058	2.8875	3.1687	—
Average received rate (a)	2.5905	2.8576	3.1678	—
Fair value (b)	1.7	0.9	0.8	—
(a) Weighted average, in dollars
(b) Millions of dollars

ITEM 4. CONTROLS AND PROCEDURES

As of September 30, 2015, SCANA conducted an evaluation under the supervision and with the participation of its management, including its CEO and CFO, of (a) the effectiveness of the design and operation of its disclosure controls and procedures and (b) any change in its internal control over financial reporting.  Based on this evaluation, the CEO and CFO concluded that, as of September 30, 2015, SCANA’s disclosure controls and procedures were effective. There has been no change in SCANA’s internal control over financial reporting during the quarter ended September 30, 2015 that has materially affected or is reasonably likely to materially affect SCANA’s internal control over financial reporting.

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SOUTH CAROLINA ELECTRIC & GAS COMPANY FINANCIAL SECTION

ITEM 1.    FINANCIAL STATEMENTS

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

Millions of dollars	September 30, 2015			December 31, 2014
Assets
Utility Plant In Service	$	11,007		$	10,650
Accumulated Depreciation and Amortization	(3,830		)	(3,667		)
Construction Work in Progress	3,734			3,302
Plant to be Retired, Net	—			169
Nuclear Fuel, Net of Accumulated Amortization	305			329
Utility Plant, Net ($694 and $675 related to VIEs)	11,216			10,783
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	67			67
Assets held in trust, net-nuclear decommissioning	113			113
Other investments	2			2
Nonutility Property and Investments, Net	182			182
Current Assets:
Cash and cash equivalents	30			100
Receivables, net of allowance for uncollectible accounts of $4 and $4	462			524
Affiliated receivables	22			109
Inventories (at average cost):
Fuel and gas supply	102			131
Materials and supplies	136			129
Prepayments	100			154
Other current assets	80			99
Total Current Assets ($100 and $158 related to VIEs)	932			1,246
Deferred Debits and Other Assets:
Pension asset	9			10
Regulatory assets	1,808			1,745
Other	165			141
Total Deferred Debits and Other Assets ($52 and $50 related to VIEs)	1,982			1,896
Total	$	14,312		$	14,107

See Notes to Condensed Consolidated Financial Statements.

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Millions of dollars	September 30, 2015			December 31, 2014
Capitalization and Liabilities
Common Stock - no par value, 40.3 million shares outstanding	$	2,756		$	2,560
Retained Earnings	2,266			2,077
Accumulated Other Comprehensive Loss	(3		)	(3		)
Total Common Equity	5,019			4,634
Noncontrolling Interest	129			123
Total Equity	5,148			4,757
Long-Term Debt, net	4,790			4,299
Total Capitalization	9,938			9,056
Current Liabilities:
Short-term borrowings	234			709
Current portion of long-term debt	10			10
Accounts payable	184			294
Affiliated payables	125			180
Customer deposits and customer prepayments	69			61
Taxes accrued	279			170
Interest accrued	66			64
Dividends declared	71			74
Derivative financial instruments	108			208
Other	76			99
Total Current Liabilities	1,222			1,869
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,682			1,696
Deferred investment tax credits	26			28
Asset retirement obligations	460			536
Postretirement benefits	198			195
Regulatory liabilities	641			610
Other	145			117
Total Deferred Credits and Other Liabilities	3,152			3,182
Commitments and Contingencies (Note 9)	—			—
Total	$	14,312		$	14,107

See Notes to Condensed Consolidated Financial Statements.

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited) 

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Millions of dollars	2015			2014			2015			2014
Operating Revenues:
Electric	$	743		$	740		$	2,013		$	2,032
Gas	63			72			275			337
Total Operating Revenues	806			812			2,288			2,369
Operating Expenses:
Fuel used in electric generation	187			213			525			640
Purchased power	14			13			38			54
Gas purchased for resale	37			46			151			210
Other operation and maintenance	148			136			428			415
Depreciation and amortization	59			79			220			236
Other taxes	54			53			163			158
Total Operating Expenses	499			540			1,525			1,713
Operating Income	307			272			763			656
Other Income (Expense):
Other income	6			9			24			71
Other expense	(7		)	(7		)	(21		)	(19		)
Interest charges, net of allowance for borrowed funds used during construction of $4, $5, $11 and $11	(63		)	(57		)	(183		)	(169		)
Allowance for equity funds used during construction	8			10			18			22
Total Other Income (Expense)	(56		)	(45		)	(162		)	(95		)
Income Before Income Tax Expense	251			227			601			561
Income Tax Expense	84			70			196			178
Net Income	167			157			405			383
Net Income Attributable to Noncontrolling Interest	(3		)	(3		)	(11		)	(9		)
Earnings Available to Common Shareholder	$	164		$	154		$	394		$	374
Dividends Declared on Common Stock	$	71		$	69		$	211		$	197

See Notes to Condensed Consolidated Financial Statements.

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
Millions of dollars	2015			2014			2015			2014
Net Income and Total Comprehensive Income	167			157			405			383
Comprehensive income attributable to noncontrolling interest	(3		)	(3		)	(11		)	(9		)
Comprehensive income available to common shareholder	$	164		$	154		$	394		$	374

See Notes to Condensed Consolidated Financial Statements.

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
Millions of dollars	2015			2014
Cash Flows From Operating Activities:
Net income	$	405		$	383
Adjustments to reconcile net income to net cash provided from operating activities:
Losses from equity method investments	3			4
Deferred income taxes, net	(14		)	76
Depreciation and amortization	221			236
Amortization of nuclear fuel	41			31
Allowance for equity funds used during construction	(18		)	(22		)
Carrying cost recovery	(9		)	(7		)
Changes in certain assets and liabilities:
Receivables	46			(34		)
Inventories	(15		)	(36		)
Prepayments	63			(24		)
Regulatory assets	90			(170		)
Regulatory liabilities	6			(130		)
Accounts payable	(21		)	11
Taxes accrued	109			(70		)
Pension and other post retirement benefits	(2		)	(12		)
Derivative financial instruments	(100		)	103
Other assets	58			27
Other liabilities	(61		)	58
Net Cash Provided From Operating Activities	802			424
Cash Flows From Investing Activities:
Property additions and construction expenditures	(748		)	(678		)
Proceeds from investments (including derivative collateral returned)	768			163
Purchase of investments (including derivative collateral posted)	(776		)	(202		)
Payments upon interest rate derivative contract settlement	(152		)	(34		)
Proceeds upon interest rate derivative contract settlement	10			—
Proceeds from investment in affiliate	80			—
Net Cash Used For Investing Activities	(818		)	(751		)
Cash Flows From Financing Activities:
Proceeds from issuance of long-term debt	491			294
Repayment of long-term debt	(10		)	(12		)
Dividends	(214		)	(190		)
Contributions from parent	200			85
Return of capital to parent	(4		)	(3		)
Short-term borrowings –affiliate, net	(42		)	(7		)
Short-term borrowings, net	(475		)	110
Net Cash Provided From (Used For) Financing Activities	(54		)	277
Net Decrease In Cash and Cash Equivalents	(70		)	(50		)
Cash and Cash Equivalents, January 1	100			92
Cash and Cash Equivalents, September 30	$	30		$	42
Supplemental Cash Flow Information:
Cash paid for– Interest (net of capitalized interest of $11 and $11)	$	169		$	162
– Income taxes paid	89			143
– Income taxes received	(84		)	—
Noncash Investing and Financing Activities:
Accrued construction expenditures	76			94
Capital leases	5			4

See Notes to Condensed Consolidated Financial Statements.

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

For the Three and Nine Months Ended September 30, 2015 and 2014

(Unaudited)

The following notes should be read in conjunction with the Notes to Consolidated Financial Statements appearing in SCE&G’s Annual Report on Form 10-K for the year ended December 31, 2014.  These are interim financial statements and, due to the seasonality of Consolidated SCE&G’s business and matters that may occur during the rest of the year, the amounts reported in the Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the full year.  In the opinion of management, the information furnished herein reflects all adjustments, all of a normal recurring nature, which are necessary for a fair statement of the results for the interim periods reported.

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Variable Interest Entities

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

GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $489 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission allowances. See also Note 4.

Plant to be Retired

At December 31, 2014, SCE&G expected to retire three units that are or were coal-fired by 2020, which was prior to the end of the previously estimated useful lives over which the units were being depreciated. As such, these units were identified as Plant to be Retired. In the third quarter of 2015, in connection with the adoption of a customary depreciation study and related analysis, SCE&G determined that these three units would not likely be retired by 2020 (see Note 2), and their depreciation rates were set to recover the units' net carrying value over their respective revised useful lives. Accordingly, the net carrying value of these units is no longer classified as Plant to be Retired at September 30, 2015.

New Accounting Matters

In May 2014, the FASB issued accounting guidance for revenue arising from contracts with customers that supersedes most current revenue recognition guidance, including industry-specific guidance. The new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. After the FASB's delay in the effective date of the revenue guidance by one year, Consolidated SCE&G is required to adopt this guidance in the first quarter of 2018 and early adoption is permitted beginning in the first quarter of 2017.  Consolidated SCE&G has not determined the impact this guidance will have on its results of operations, cash flows or financial position.

In April 2015, the FASB issued accounting guidance intended to simplify the presentation of debt issuance costs by requiring that such costs be deducted from the carrying amounts related to debt liabilities when presented in the balance sheet. As permitted, Consolidated SCE&G expects to early adopt this guidance in the fourth quarter of 2015.  Consolidated SCE&G

46

does not expect the adoption of this guidance to have a significant impact on its financial position.  The guidance will not affect Consolidated SCE&G’s results of operations or cash flows.

In April 2015, the FASB issued accounting guidance related to fees paid by a customer in a cloud computing arrangement.  Among other things, the guidance clarifies how to account for a software license element included in a cloud computing arrangement, and makes explicit that a cloud computing arrangement not containing a software license element should be accounted for as a service contract. Consolidated SCE&G has evaluated this guidance and has determined it will not significantly impact its results of operations, cash flows or financial position. Consolidated SCE&G expects to adopt this guidance in the first quarter of 2016.

In July 2015, the FASB issued accounting guidance intended to simplify the subsequent measurement of inventory cost by requiring most inventory to be measured at the lower of cost and net realizable value when presented in the balance sheet. Consolidated SCE&G expects to adopt this guidance in the first quarter of 2017. Consolidated SCE&G is evaluating this guidance and has not determined what impact it will have on its results of operations, cash flows or financial position.

2. RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric - Cost of Fuel

SCE&G's retail electric rates include a cost of fuel component approved by the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased.

Pursuant to an April 2014 SCPSC order, SCE&G increased its base fuel cost component by approximately $10.3 million for the 12-month period beginning with the first billing cycle of May 2014. The base fuel cost increase was offset by a reduction in SCE&G's rate rider related to pension costs approved by the SCPSC in March 2014. In addition, pursuant to the April 2014 order, electric revenue for 2014 was reduced by approximately $46 million for adjustments to the fuel cost component and related under-collected fuel balance. Such adjustments are fully offset by the recognition within other income of gains realized from the late 2013 settlement of certain interest rate derivatives which had been entered into in anticipation of the issuance of long-term debt, which gains had been deferred as a regulatory liability. The order also provided for the accrual of certain debt-related carrying costs on its under-collected balance of base fuel costs during the period May 1, 2014 through April 30, 2015.

The cost of fuel includes amounts paid by SCE&G pursuant to the Nuclear Waste Act for the disposal of spent nuclear fuel. As a result of a November 2013 decision by the Court of Appeals, the DOE set the Nuclear Waste Act fee to zero effective May 16, 2014. The impact of changes to the Nuclear Waste Act fee is considered during annual fuel rate proceedings.

By order dated April 30, 2015, the SCPSC approved a settlement agreement among SCE&G and certain other parties in which SCE&G agreed to decrease the total fuel cost component of its retail electric rates. Under this order, SCE&G is to recover an amount equal to its under-collected balance of base fuel and variable environmental costs as of April 30, 2015, over the subsequent 12-month period beginning with the first billing cycle of May 2015.

By order dated July 15, 2015, the SCPSC approved a settlement agreement among SCE&G and certain other parties concerning SCE&G's petition for approval to participate in a DER program and to recover DER program costs as a separate component of SCE&G's overall fuel factor. Under this order, SCE&G will, among other things, develop renewable energy facilities with a nameplate capacity of at least 84.5 MW by the end of 2020 and have at least 30 MW of utility-scale solar capacity in service by the end of 2016. The order also requires SCE&G to develop incentives for solar energy generated by residential and commercial customers. SCE&G will also make incentives available for residential customers receiving solar power from community solar-programs.

By order dated September 16, 2015, the SCPSC approved SCE&G's request to adopt lower depreciation rates for electric and common plant effective January 1, 2015 resulting in $29 million in lower depreciation expense annually. These rates were based on the results of a depreciation study conducted by SCE&G using utility plant balances as of December 31, 2014. In connection with the adoption of the revised depreciation rates, SCE&G recorded lower depreciation expense of approximately $22 million in the third quarter of 2015, and pursuant to the SCPSC order, SCE&G reduced its electric operating revenues by approximately $14.5 million with an offset to under-collected fuel included within Receivables in the balance

47

sheet. Accordingly, Consolidated SCE&G's net income for each of the three and nine months ended September 30, 2015, increased approximately $4.5 million as a result of this change in estimate.

Electric - Base Rates

Pursuant to an SCPSC order, SCE&G removes from rate base deferred income tax assets arising from capital expenditures related to the New Units and accrues carrying costs on those amounts during periods in which they are not included in rate base.  Such carrying costs are determined at SCE&G’s weighted average long-term debt borrowing rate and are recorded as a regulatory asset and other income. Carrying costs during the three and nine months ended September 30, 2015 totaled $2.4 million and $6.5 million, respectively, and during the three and nine months ended September 30, 2014 totaled $1.6 million and $4.1 million, respectively. SCE&G anticipates that when the New Units are placed in service and accelerated tax depreciation is recognized on them, these deferred income tax assets will decline. When these assets are fully offset by related deferred income tax liabilities, the carrying cost accruals will cease, and the regulatory asset will begin to be amortized.

The SCPSC has approved a suite of DSM Programs for development and implementation. SCE&G offers to its retail electric customers several distinct programs designed to assist customers in reducing their demand for electricity and improving their energy efficiency. SCE&G submits annual filings to the SCPSC related to these programs which include actual program costs, net lost revenues both forecasted and actual), customer incentives, and net program benefits, among other things. As actual DSM Program costs are incurred, they are deferred as regulatory assets (see Regulatory Assets and Regulatory Liabilities below) and recovered through a rate rider approved by the SCPSC. The rate rider also provides for recovery of net lost revenues and for a shared savings incentive. The SCPSC approved the following rate riders pursuant to the annual DSM Programs filings, which went into effect as indicated below:

Year	Effective	Amount
2015	First billing cycle of May	$	32.0	million
2014	First billing cycle of May	$	15.4	million
2013	First billing cycle of May	$	16.9	million

In April 2014, the SCPSC issued an order approving, among other things, SCE&G’s request to utilize approximately $17.8 million of the gains from the late 2013 settlement of certain interest rate derivative instruments, previously deferred as regulatory liabilities, to offset a portion of SCE&G’s DSM Programs rate rider. This order also allowed SCE&G to apply $5.0 million of its storm damage reserve and $5.0 million of the gains from the settlement of certain interest rate derivative instruments to offset previously deferred amounts. 

Electric – BLRA

Under the BLRA, SCE&G may file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation. Through 2015, requested rate adjustments have been based on SCE&G's updated cost of debt and capital structure and on an allowed return on common equity of 11.0%. The SCPSC has approved recovery of the following amounts under the BLRA effective for bills rendered on and after October 30 in the following years:

Year	Action			Amount
2015	2.6	%	Increase	$	64.5	million
2014	2.8	%	Increase	$	66.2	million
2013	2.9	%	Increase	$	67.2	million

In September 2015 the SCPSC approved a revision to the allowed return on equity for new nuclear construction from 11.0% to 10.5%. This revised return on equity will be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2016, until such time as the New Units are completed. See Note 9.

Gas

The RSA is designed to reduce the volatility of costs charged to customers by allowing for more timely recovery of the costs that regulated utilities incur related to natural gas infrastructure.  The SCPSC has approved the following rate changes pursuant to annual RSA filings effective with the first billing cycle of November in the following years: 

48

Year	Action			Amount
2015	No change			-
2014	0.6	%	Decrease	$	2.6	million
2013	No change			-

SCE&G's natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred, including transportation costs. SCE&G's gas rates are calculated using a methodology which may adjust the cost of gas monthly based on a 12-month rolling average, and its gas purchasing policies and practices are reviewed annually by the SCPSC. The annual review conducted for the 12-month period ended July 31, 2014 resulted in the SCPSC issuing an order finding that SCE&G's gas purchasing policies and practices during the review period were reasonable and prudent. SCE&G's 2015 annual PGA hearing was held on November 5, 2015 and the SCPSC's decision is pending.

Regulatory Assets and Regulatory Liabilities

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

Millions of dollars	September 30, 2015		December 31, 2014
Regulatory Assets:
Accumulated deferred income taxes	$	278	$	278
Under collections – electric fuel adjustment clause	—		20
Environmental remediation costs	35		36
AROs and related funding	356		347
Franchise agreements	23		26
Deferred employee benefit plan costs	296		310
Planned major maintenance	—		2
Deferred losses on interest rate derivatives	538		453
Deferred pollution control costs	35		36
Unrecovered plant	128		137
DSM Programs	59		56
Carrying costs on deferred tax assets related to nuclear construction	15		9
Other	45		35
Total Regulatory Assets	$	1,808	$	1,745

Regulatory Liabilities:
Accumulated deferred income taxes	$	16	$	17
Asset removal costs	520		505
Storm damage reserve	6		6
Deferred gains on interest rate derivatives	87		82
Planned major maintenance	12		—
Total Regulatory Liabilities	$	641	$	610

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

Under-collections - electric fuel adjustment clause represent amounts due from customers pursuant to the fuel adjustment clause as approved by the SCPSC which are expected to be recovered in retail electric rates over periods exceeding 12 months. 

49

Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by SCE&G and are expected to be recovered over periods of up to approximately 24 years.

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

Franchise agreements represent costs associated with electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. Based on an SCPSC order, SCE&G is recovering these amounts through cost of service rates through approximately 2021.

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

Planned major maintenance related to certain fossil fueled turbine/generation equipment and nuclear refueling outages is accrued in periods other than when incurred, pursuant to specific SCPSC orders.  SCE&G collects and accrues $18.4 million annually for fossil fueled turbine/generation equipment maintenance and collects and accrues $17.2 million annually for nuclear-related refueling charges.

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

Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the scrubbers installed at certain coal-fired generating plants pursuant to specific regulatory orders.  Such costs are being recovered through utility rates through 2045. 

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

DSM Programs represent deferred costs associated with such programs.  As a result of an April 2015 SCPSC order, deferred costs are currently being recovered over approximately five years through an approved rate rider. 

Carrying costs on deferred tax assets related to nuclear construction are calculated on accumulated deferred income tax assets associated with the New Units which are not part of electric rate base using the weighted average long-term debt cost of capital. These carrying costs will be amortized over ten years beginning in approximately 2021.

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

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

The storm damage reserve represents an SCPSC-approved collection through SCE&G electric rates, capped at $100 million, which can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year. Pursuant to specific regulatory orders, SCE&G has suspended storm damage reserve collection through rates indefinitely. During the nine months ended September 30, 2015, no amounts were applied to offset incremental storm damage costs.

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

3. EQUITY

Changes in common equity during the nine months ended September 30, 2015 and 2014 were as follows:

	Common Stock			Retained			Accumulated Other Comprehensive			Noncontrolling			Total
Millions	Shares	Amount		Earnings			Income (Loss)			Interest			Equity
Balance at January 1, 2015	40	$	2,560	$	2,077		$	(3	)	$	123		$	4,757
Earnings available to common shareholder				394						11			405
Deferred cost of employee benefit plans							—						—
Total Comprehensive Income				394			—			11			405
Capital contributions from parent		196											196
Cash dividend declared				(205		)				(5		)	(210		)
Balance at September 30, 2015	40	$	2,756	$	2,266		$	(3	)	$	129		$	5,148
Balance at January 1, 2014	40	$	2,479	$	1,896		$	(3	)	$	117		$	4,489
Earnings available to common shareholder				374						9			383
Deferred cost of employee benefit plans							—						—
Total Comprehensive Income				374			—			9			383
Capital contributions from parent		82											82
Cash dividend declared				(192		)				(5		)	(197		)
Balance at September 30, 2014	40	$	2,561	$	2,078		$	(3	)	$	121		$	4,757

SCE&G had 50 million shares of common stock authorized as of September 30, 2015 and December 31, 2014. SCE&G had 20 million shares of preferred stock authorized as of September 30, 2015 and December 31, 2014, of which 1,000 shares at a stated value of $100,000 were issued and outstanding during all periods presented. All issued and outstanding shares of SCE&G's common and preferred stock are held by SCANA.

Reclassifications from AOCI into earnings of the amortization of deferred employee benefit costs were not significant for any period presented.

4. LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

In May 2014, SCE&G issued $300 million of 4.5% first mortgage bonds due June 1, 2064. Proceeds from this sale were used to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes.

In May 2015, SCE&G issued $500 million of 5.1% first mortgage bonds due June 1, 2065. Proceeds from this sale were used to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes.

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

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Liquidity

SCE&G (including Fuel Company) had available the following committed LOC, and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations:

Millions of dollars	September 30, 2015			December 31, 2014
Lines of credit:
Total committed long-term	$	1,400		$	1,400
Outstanding commercial paper (270 or fewer days)	$	234		$	709
Weighted average interest rate	0.44		%	0.52		%
Letters of credit supported by LOC	$	0.3		$	0.3
Available	$	1,166		$	691

SCE&G and Fuel Company are parties to five-year credit agreements in the amount of $1.2 billion (of which $500 million relates to Fuel Company), which expire in October 2019. In addition, SCE&G is a party to a three-year credit agreement in the amount of $200 million, which expires in October 2016. These credit agreements are used for general corporate purposes, including liquidity support for each company’s commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, certain fossil fuels, and emission and other environmental allowances. These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provide 10.7% of the aggregate $1.4 billion credit facilities, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A., Credit Suisse AG, Cayman Islands Branch and UBS Loan Finance LLC each provide 8.9% and Branch Banking and Trust Company, Union Bank, N.A. and U.S. Bank National Association each provide 6.3%.  Two other banks provide the remaining support. Consolidated SCE&G pays fees to the banks as compensation for maintaining the committed lines of credit. Such fees were not material in any period presented.

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

Consolidated SCE&G participates in a utility money pool with SCANA and certain other subsidiaries of SCANA. Money pool borrowings and investments bear interest at short-term market rates. Consolidated SCE&G’s interest income and expense from money pool transactions were not significant for any period presented. At September 30, 2015, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $41.2 million. At December 31, 2014, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $83.0 million and money pool investments due from an affiliate of $80.0 million.

5. INCOME TAXES

Between 2013 and 2015, in addition to filing current year tax returns, SCANA amended certain of its tax returns. These returns claimed certain tax-defined research and development deductions and credits. In connection with these filings, Consolidated SCE&G recorded an unrecognized tax benefit of $18 million. If recognized, $14 million of the tax benefit would affect Consolidated SCE&G’s effective tax rate. It is reasonably possible that this tax benefit will increase by an additional $2 million within the next 12 months. It is also reasonably possible that this tax benefit may decrease by $8 million. within the next 12 months. No other material changes in the status of Consolidated SCE&G’s tax positions have occurred through September 30, 2015.

                Consolidated SCE&G recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses.  Consolidated SCE&G has not recorded any interest expense or penalties associated with these positions.

6. DERIVATIVE FINANCIAL INSTRUMENTS

Consolidated SCE&G recognizes all derivative instruments as either assets or liabilities in the statement of financial position and measures those instruments at fair value.  Consolidated SCE&G recognizes changes in the fair value of derivative instruments either in earnings or within regulatory assets or regulatory liabilities, depending upon the intended use of the derivative and the resulting designation. 

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

Interest Rate Swaps

Consolidated SCE&G synthetically converts variable rate debt to fixed rate debt using swaps that are designated as cash flow hedges. Periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense.

In anticipation of the issuance of debt, Consolidated SCE&G may use treasury rate locks or forward starting swap agreements. Pursuant to regulatory orders, interest rate derivatives entered into by SCE&G after October 2013 are not designated as cash flow hedges, and all related fair value changes and settlement amounts are recorded as regulatory assets or liabilities. Interest rate derivatives entered into by SCE&G before October 2013, and all such derivatives entered into by GENCO, were designated as cash flow hedges, and for such instruments only the effective portion of fair value changes and settlement amounts are recorded in regulatory assets or regulatory liabilities. Upon settlement, losses on swaps are amortized over the lives of related debt issuances, and gains are applied to under-collected fuel, are amortized to interest expense or are applied as otherwise directed by the SCPSC.

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

Quantitative Disclosures Related to Derivatives

GENCO was party to an interest rate swap designated as a cash flow hedge with a notional amount of $36.4 million at September 30, 2015 and $36.4 million at December 31, 2014. SCE&G was party to interest rate swaps not designated as cash flow hedges with an aggregate notional amount of $1.2 billion at September 30, 2015 and $1.1 billion at December 31, 2014, respectively.

The fair value of interest rate derivatives was as follows:

Fair Values of Derivative Instruments
		Fair Value
Millions of dollars	Balance Sheet Location	Asset		Liability
As of September 30, 2015
Designated as hedging instruments
Interest rate contracts	Derivative financial instruments			$	1
	Other deferred credits and other liabilities			10
Total				$	11
Not designated as hedging instruments
Interest rate contracts	Derivative financial instruments	—		$	107
	Other deferred debits and other assets	$	6
	Other deferred credits and other liabilities	—		60
Total		$	6	$	167
As of December 31, 2014
Designated as hedging instruments
Interest rate contracts	Derivative financial instruments			$	1
	Other deferred credits and other liabilities			8
Total				$	9
Not designated as hedging instruments
Interest rate contracts	Derivative financial instruments			$	207
	Other deferred credits and other liabilities			17
Total				$	224

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

Derivatives in Cash Flow Hedging Relationships

	Loss Deferred in Regulatory Accounts							Loss Reclassified from Deferred Accounts into Income
	(Effective Portion)							(Effective Portion)
Millions of dollars	2015			2014			Location	2015			2014
Three Months Ended September 30,
Interest rate contracts	$	(3	)	$	(1	)	Interest expense	$	(1	)	$	(1	)
Nine Months Ended September 30,
Interest rate contracts	$	(3	)	$	(5	)	Interest expense	$	(2	)	$	(2	)

As of September 30, 2015, Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $2.3 million as an increase to interest expense, assuming financial markets remain at their current levels.

Hedge Ineffectiveness

Ineffectiveness on interest rate hedges designated as cash flow hedges was insignificant during all periods presented.

Derivatives not designated as Hedging Instruments

	Loss Deferred in Regulatory Accounts							Gain Reclassified from Deferred Accounts into Income
Millions of dollars	2015			2014			Location	2015		2014
Three Months Ended September 30,
Interest rate contracts	$	(116	)	$	(35	)	Other income	—		$	5
Nine Months Ended September 30,
Interest rate contracts	$	(79	)	$	(220	)	Other income	$	5	$	60

As of September 30, 2015, Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from derivatives not designated as hedges will include $0.6 million as an increase to interest expense.

Credit Risk Considerations

Consolidated SCE&G limits credit risk in its derivatives activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. In this regard, Consolidated SCE&G uses credit ratings provided by credit rating agencies and current market-based qualitative and quantitative data as well as financial statements, to assess the financial health of counterparties. Consolidated SCE&G uses standardized master agreements which may include collateral requirements. These master agreements permit the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements permit the secured party to demand the posting of cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with Consolidated SCE&G's credit policies and due diligence. In addition, collateral agreements allow for the termination and liquidation of all positions in the event of a failure or inability to post collateral.

Certain of Consolidated SCE&G’s derivative instruments contain contingent provisions that may require Consolidated SCE&G to provide collateral upon the occurrence of specific events, primarily credit downgrades.  As of September 30, 2015 and December 31, 2014, Consolidated SCE&G had posted $108.9 million and $107.1 million, respectively, of collateral related to derivatives with contingent provisions that were in a net liability position.  Collateral related to the positions expected to close in the next 12 months are recorded in Other Current Assets on the condensed consolidated balance sheets. Collateral related to noncurrent positions is recorded in Other within Deferred Debits and Other Assets on the condensed consolidated balance sheets. If all of the contingent features underlying these instruments had been fully triggered as of September 30, 2015 and December 31, 2014, Consolidated SCE&G could have been required to post an additional $65.8 million and $125.9 million, respectively, of collateral with its counterparties.  The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of September 30, 2015 and December 31, 2014 is $174.7 million and $233.0 million, respectively.

In addition, as of September 30, 2015 and December 31, 2014, Consolidated SCE&G has collected no cash collateral related to interest rate derivatives with contingent provisions that are in a net asset position. If all the contingent features underlying these instruments had been fully triggered as of September 30, 2015 and December 31, 2014, Consolidated SCE&G could request $2.8 million and $- million, respectively, of cash collateral from its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net asset position as of September 30, 2015 and December 31, 2014 is $2.8 million and $- million, respectively.

Information related to Consolidated SCE&G's derivative assets follows:

	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position				Net Amount
Millions of dollars						Financial Instruments			Cash Collateral Received
As of September 30, 2015
Interest rate contracts	$	6	—	$	6	$	(3	)	—	$	3
Balance Sheet Location	Other deferred debits and other assets			$	6

As of December 31, 2014, Consolidated SCE&G had no derivative assets.

Information related to Consolidated SCE&G's derivative liabilities follows:

	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position						Net Amount
Millions of dollars						Financial Instruments			Cash Collateral Posted
As of September 30, 2015
Interest rate contracts	$	178	—	$	178	$	(3	)	$	(109	)	$	66
Balance Sheet Location	Derivative financial instruments			$	108
	Other deferred credits and other liabilities			70
	Total			$	178

As of December 31, 2014
Interest rate contracts	$	233	—	$	233	—	$	(107	)	$	126
Balance Sheet Location	Derivative financial instruments			$	208
	Other deferred credits and other liabilities			25
	Total			$	233

7. FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

Consolidated SCE&G’s interest rate swap agreements are valued using discounted cash flow models with independently sourced data.  Fair value Level 2 measurements were as follows:

Millions of dollars		September 30, 2015		December 31, 2014
Assets -	Interest rate contracts	$	6	—
Liabilities -	Interest rate contracts	178		$	233

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

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

	September 30, 2015				December 31, 2014
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	4,801.0	$	5,277.6	$	4,308.6	$	5,070.9

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

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

8. EMPLOYEE BENEFIT PLANS

Consolidated SCE&G participates in SCANA’s noncontributory defined benefit pension plan, which covers the majority of all regular, full-time employees, and also participates in SCANA’s unfunded postretirement health care and life insurance programs, which provide benefits to retired employees.  Components of net periodic benefit cost recorded by Consolidated SCE&G were as follows:

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2015			2014			2015		2014
Three months ended September 30,
Service cost	$	5.3		$	4.0		$	1.0	$	0.7
Interest cost	8.1			8.4			2.2		2.3
Expected return on assets	(13.0		)	(13.9		)	—		—
Prior service cost amortization	0.8			0.9			0.1		—
Amortization of actuarial losses (gains)	2.7			0.8			0.3		(0.2		)
Net periodic benefit cost	$	3.9		$	0.2		$	3.6	$	2.8

Nine months ended September 30,
Service cost	$	14.5		$	12.0		$	3.2	$	2.7
Interest cost	24.1			25.6			6.8		7.1
Expected return on assets	(39.1		)	(42.2		)	—		—
Prior service cost amortization	2.5			2.6			0.2		0.2
Amortization of actuarial losses	8.6			3.0			1.2		—
Net periodic benefit cost	$	10.6		$	1.0		$	11.4	$	10.0

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

9. COMMITMENTS AND CONTINGENCIES

 Nuclear Insurance

Under Price-Anderson, SCE&G (for itself and on behalf of Santee Cooper, a one-third owner of Summer Station Unit 1) maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at SCE&G's nuclear power plant. Price-Anderson provides funds up to $12.9 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $375 million by ANI with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. Each reactor licensee is currently liable for up to $127.3 million per reactor owned for each nuclear incident occurring at any reactor in the United States,

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provided that not more than $18.9 million of the liability per reactor would be assessed per year.  SCE&G’s maximum assessment, based on its two-thirds ownership of Summer Station Unit 1, would be $84.8 million per incident, but not more than $12.6 million per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years.

SCE&G currently maintains insurance policies (for itself and on behalf of Santee Cooper) with NEIL.  The policies provide coverage to Summer Station Unit 1 for property damage and outage costs up to $2.75 billion resulting from an event of nuclear origin. In addition, a builder's risk insurance policy has been purchased from NEIL for the construction of the New Units. This policy provides the owners of the New Units up to $500 million in limits of accidental property damage occurring during construction. The NEIL policies, in the aggregate, are subject to a maximum loss of $2.75 billion for any single loss occurrence. All of the NEIL policies permit retrospective assessments under certain conditions to cover insurer’s losses.  Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $45.9 million.

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

New Nuclear Construction

In 2008, SCE&G, on behalf of itself and as agent for Santee Cooper, contracted with the Consortium for the design and construction of the New Units at the site of Summer Station.  

SCE&G's current ownership share in the New Units is 55%. As discussed below, under an agreement signed in January 2014 (and subject to customary closing conditions, including necessary regulatory approvals), SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper.

EPC Contract and BLRA Matters

The construction of the New Units and SCE&G’s related recovery of financing costs through rates is subject to review and approval by the SCPSC as provided for in the BLRA. Under the BLRA, the SCPSC has approved, among other things, a milestone schedule and a capital costs estimates schedule for the New Units. This approval constitutes a final and binding determination that the New Units are used and useful for utility purposes, and that the capital costs associated with the New Units are prudent utility costs and expenses and are properly included in rates, so long as the New Units are constructed or are being constructed within the parameters of the approved milestone schedule, including specified schedule contingencies, and the approved capital costs estimates schedule. Subject to the same conditions, the BLRA provides that SCE&G may apply to the SCPSC annually for an order to recover through revised rates SCE&G’s weighted average cost of capital applied to all or part of the outstanding balance of construction work in progress concerning the New Units. Such annual rate changes are described in Note 2. As of September 30, 2015, SCE&G’s investment in the New Units, including related transmission, totaled $3.3 billion, for which the financing costs on $2.4 billion have been reflected in rates under the BLRA.

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

Since the settlement of delay-related claims in 2012, the Consortium has continued to experience delays in the schedule, including those related to fabrication and delivery of sub-modules for the New Units. The fabrication and delivery of sub-modules have been and remain focus areas of the Consortium. Shield building panels are considered critical path items for both New Units, and the current schedule for production of such panels will require mitigation to support the updated substantial completion dates (see below).

During the fourth quarter of 2013, the Consortium began a full re-baselining of the Unit 2 and Unit 3 construction schedules to incorporate a more detailed evaluation of the engineering and procurement activities necessary to accomplish the

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schedules and to provide a detailed reassessment of the impact of the revised Unit 2 and Unit 3 schedules on engineering and design resource allocations, procurement, construction work crew efficiencies, and other items. The result was a revised, fully integrated project schedule with timing of specific construction activities (Revised, Fully-Integrated Construction Schedule) along with related cost information.

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

In September 2015, the SCPSC approved an updated BLRA milestone schedule based on revised substantial completion dates for Units 2 and 3 of June 2019 and June 2020, respectively, each subject to an 18-month contingency period. In addition, the SCPSC approved certain updated owner's costs ($245 million) and other capital costs ($453 million), of which $539 million were associated with the schedule delays and other contested costs. SCE&G's total projected capital costs (in 2007 dollars) and gross construction cost estimates (including escalation and AFC) were estimated to be $5.2 billion and $6.8 billion, respectively. These projections included cost amounts related to the Revised, Fully-Integrated Construction Schedule for which SCE&G had not accepted responsibility and which were the subject of dispute. As such, these updated milestone schedule and projections did not reflect the resolution of negotiations. In addition, the SCPSC approved a revision to the allowed return on equity for new nuclear construction from 11.00% to 10.50%. This revised return on equity will be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2016, until such time as the New Units are completed.

On October 27, 2015, SCE&G, Santee Cooper and the Consortium reached a settlement regarding the above mentioned disputes, and the EPC Contract was amended. The October 2015 Amendment will become effective upon the consummation of the acquisition by WEC of the stock of Stone & Webster from CB&I, and will become null and void in the event such acquisition is not consummated by March 31, 2016. Following that acquisition, Stone & Webster will continue to be a member of the Consortium as a subsidiary of WEC rather than CB&I, and WEC intends to engage Fluor Corporation or its affiliate(s) as a subcontracted construction manager.

Among other things, upon effectiveness, the October 2015 Amendment would (i) resolve by settlement and release substantially all outstanding disputes between SCE&G and the Consortium, in exchange for (a) an additional cost to be paid by SCE&G and Santee Cooper of $300 million (SCE&G’s 55% portion being $165 million) and an increase in the fixed component of the contract price by that amount, and (b) a credit to SCE&G and Santee Cooper of $50 million (SCE&G’s 55% portion being approximately $27 million) to be applied to the target component of the contract price, (ii) revise the guaranteed substantial completion dates of Units 2 and 3 to August 31, 2019 and 2020, respectively, (iii) revise the delay-related liquidated damages computation requirements, including those related to the eligibility of the New Units to earn Internal Revenue Code Section 45J production tax credits (see also below), and cap those aggregate liquidated damages at $463 million per New Unit (SCE&G’s 55% portion being approximately $255 million per New Unit), (iv) provide for payment to the Consortium of a completion bonus of $275 million per New Unit (SCE&G’s 55% portion being approximately $151 million per New Unit) for each New Unit placed in service by the deadline to qualify for production tax credits, (v) provide for the development of a revised construction milestone payment schedule, with SCE&G and Santee Cooper making monthly payments of $100 million (SCE&G’s 55% portion being $55 million) for each of the first five months following effectiveness, followed by payments made based on milestones achieved, and (vi) provide that SCE&G and Santee Cooper waive and cancel the CB&I parent company guaranty with respect to the project. The payment obligations under the EPC Contract are joint and several obligations of WEC and Stone & Webster, and the October 2015 Amendment provides for Toshiba Corporation, WEC’s parent company, to reaffirm its guaranty of WEC’s payment obligations. Under the October 2015 Amendment, SCE&G’s total estimated project costs will increase by approximately $286 million over the $6.8 billion approved by the SCPSC in September 2015, and will bring its total estimated gross construction cost of the project (including escalation and AFC) to approximately $7.1 billion.

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

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Finally, upon effectiveness, the October 2015 Amendment would provide SCE&G and Santee Cooper an irrevocable option, until November 1, 2016 and subject to regulatory approvals, to further amend the EPC Contract to fix the total amount to be paid to the Consortium for its entire scope of work on the project (excluding a limited amount of work within the time and materials component of the contract price) after June 30, 2015 at $6.082 billion (SCE&G’s 55% portion being approximately $3.345 billion). This total amount to be paid would be subject to adjustment for amounts paid since June 30, 2015. Were this fixed price option to be exercised, the aggregate delay-related liquidated damages amount referred to in (iii) above would be capped at $338 million per unit (SCE&G’s 55% portion being approximately $186 million per unit), and the completion bonus amounts referred to in (iv) above would be $150 million per New Unit (SCE&G’s 55% portion being approximately $83 million per New Unit). The exercise of this fixed price option would result in SCE&G’s total estimated project costs increasing by approximately $774 million over the $6.8 billion approved by the SCPSC in September 2015, and would bring its total estimated gross construction cost (including escalation and AFC) of the project to approximately $7.6 billion.

Resolution of the disputes as described in (i) above, or in the case of the exercise of the fixed price option, would result in estimated project costs above the amounts approved by the SCPSC; however, the guaranteed substantial completion dates fall within the SCPSC approved 18-month contingency periods. SCE&G expects to hold an allowable ex parte communication briefing with the SCPSC on November 19, 2015 and, following an evaluation as to whether to exercise the fixed price option, expects to file a petition, as provided under the BLRA, for an update to the project’s estimated capital cost schedule which would incorporate the impact of this October 2015 Amendment.

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

Santee Cooper Matters

As noted above, SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper. Under the terms of this agreement, SCE&G will acquire a 1% ownership interest in the New Units at the commercial operation date of Unit 2, an additional 2% ownership interest no later than the first anniversary of such commercial operation date, and the final 2% no later than the second anniversary of such commercial operation date. SCE&G has agreed to pay an amount equal to Santee Cooper's actual cost, including its cost of financing, of the percentage conveyed as of the date of each conveyance. In addition, the agreement provides that Santee Cooper will not transfer any of its remaining interest in the New Units to third parties until the New Units are complete. This transaction will not affect the payment obligations between the parties during construction for the New Units, nor is it anticipated that the payments for the additional ownership interest would be reflected in a revised rates filing under the BLRA. Based on the current milestone schedule and capital costs schedule approved by the SCPSC in September 2015 and without considering the October 2015 Amendment discussed above, SCE&G’s estimated cost would be approximately $750 million for the additional 5% interest being acquired from Santee Cooper.

Nuclear Production Tax Credits

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

Other Project Matters

When the NRC issued the COLs for the New Units, two of the conditions that it imposed were requiring inspection and testing of certain components of the New Units' passive cooling system, and requiring the development of strategies to respond to extreme natural events resulting in the loss of power at the New Units. In addition, the NRC directed the Office of New Reactors to issue to SCE&G an order requiring enhanced, reliable spent fuel pool instrumentation. SCE&G prepared and submitted an integrated response plan for the New Units to the NRC in August 2013. That plan is currently under review by the

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

Environmental

Consolidated SCE&G's operations are subject to extensive regulation by various federal and state authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes. Applicable statutes and rules include the CAA, CWA, Nuclear Waste Act and CERCLA, among others. In many cases, regulations proposed by such authorities could have a significant impact on Consolidated SCE&G's financial condition, results of operations and cash flows. In addition, Consolidated SCE&G often cannot predict what conditions or requirements will be imposed by regulatory or legislative proposals. To the extent that compliance with environmental regulations or legislation results in capital expenditures or operating costs, Consolidated SCE&G expects to recover such expenditures and costs through existing ratemaking provisions.

From a regulatory perspective, SCE&G and GENCO continually monitor and evaluate their current and projected emission levels and strive to comply with all state and federal regulations regarding those emissions. SCE&G and GENCO participate in the sulfur dioxide and nitrogen oxide emission allowance programs with respect to coal plant emissions and also have constructed additional pollution control equipment at several larger coal-fired electric generating plants. Further, SCE&G is engaged in construction activities of the New Units which are expected to reduce GHG emission levels significantly once they are completed and dispatched by potentially displacing some of the current coal-fired generation sources. These actions are expected to address many of the rules and regulations discussed herein.

On August 3, 2015, the EPA issued a revised carbon standard for new power plants by re-proposing NSPS under the CAA for emissions of carbon dioxide from newly constructed fossil fuel-fired units. The final rule requires all new coal-fired power plants to meet a carbon emission rate of 1,400 pounds carbon dioxide per MWh and new natural gas units to meet 1,000 pounds carbon dioxide per MWh. While most new natural gas plants will not be required to include any new technologies, no new coal-fired plants could be constructed without partial carbon capture and sequestration capabilities. SCE&G and GENCO are evaluating the final rule, but do not plan to construct new coal-fired units in the foreseeable future. In addition, on August 3, 2015, the EPA issued its final rule on emission guidelines for states to follow in developing plans to address GHG emissions from existing units. The rule includes state-specific goals for reducing national carbon dioxide emissions by 32% from 2005 levels by 2030. The rule also provides for nuclear reactors under construction, such as the New Units, to count towards compliance and establishes a phased-in compliance approach beginning in 2022. Consolidated SCE&G is currently evaluating the rule and expects any costs incurred to comply with such rule to be recoverable through rates.

In July 2011, the EPA issued the CSAPR to reduce emissions of sulfur dioxide and nitrogen oxide from power plants in the eastern half of the United States. A series of court actions stayed this rule until October 23, 2014, when the Court of Appeals granted a motion to lift the stay. On December 3, 2014, the EPA published an interim final rule that aligns the dates in the CSAPR text with the revised court-ordered schedule, thus delaying the implementation dates to 2015 for Phase 1 and to 2017 for Phase 2. The CSAPR replaces the CAIR and requires a total of 28 states to reduce annual sulfur dioxide emissions and annual or ozone season nitrogen oxide emissions to assist in attaining the ozone and fine particle NAAQS. The rule establishes an emissions cap for sulfur dioxide and nitrogen oxide and limits the trading for emission allowances by separating affected states into two groups with no trading between the groups. On July 28, 2015, the Court of Appeals held that Phase 2 emissions budgets for certain states, including South Carolina, required reductions in emissions beyond the point necessary to achieve downwind attainment and were, therefore, invalid. The Court of Appeals remanded CSAPR, without vacating the rule, to the EPA for further consideration. The opinion of the Court of Appeals has no immediate impact on SCE&G and GENCO or their generation operations. Air quality control installations that SCE&G and GENCO have already completed have positioned them to comply with the existing allowances set by the CSAPR. Any cost incurred to comply with CSAPR are expected to be recoverable through rates.

In April 2012, the EPA's MATS rule containing new standards for mercury and other specified air pollutants became effective.  The rule provides up to four years for generating facilities to meet the standards, and SCE&G and GENCO's evaluation of the rule is ongoing. SCE&G's decision to retire certain coal-fired units (see Note 2) and its project to build the New Units along with other actions are expected to result in SCE&G's compliance with MATS.

On November 19, 2014, the EPA finalized its reconsideration of certain provisions applicable during startup and shutdown of generating facilities. SCE&G and GENCO have received a one year extension (until April 2016) to comply with MATS at Cope, McMeekin, Wateree and Williams Stations. These extensions will allow time to convert McMeekin Station to burn natural gas and to install additional pollution control devices at the other plants that will enhance the control of certain MATS-regulated pollutants. On June 29, 2015, the U.S. Supreme Court ruled that the EPA unreasonably failed to consider

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costs in its decision to regulate, and remanded a case challenging the regulation on that basis to the Court of Appeals. The ruling, however, is not expected to have an impact on SCE&G or GENCO due to the aforementioned retirements and conversions.

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

The CWA Section 316(b) Existing Facilities Rule became effective in October 2014. This rule establishes national requirements for the location, design, construction and capacity of cooling water intake structures at existing facilities that reflect the best technology available for minimizing the adverse environmental impacts of impingement and entrainment. SCE&G and GENCO are conducting studies and implementing plans to ensure compliance with this rule. In addition, Congress is expected to consider further amendments to the CWA. Such legislation may include toxicity-based standards as well as limitations to mixing zones.

On April 17, 2015, the EPA's final rule for CCR was published in the Federal Register and became effective in the fourth quarter of 2015. This rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act and imposes certain requirements on ash storage ponds and other CCR management facilities at SCE&G's and GENCO's coal-fired generating facilities. Although the full effects of this rule are still being evaluated, SCE&G and GENCO have already closed or have begun the process of closure of all of their ash storage ponds and have previously recognized AROs for such ash storage ponds under existing requirements. Consolidated SCE&G does not expect the incremental compliance costs associated with this rule to be significant and expects to recover such costs in future rates.

The Nuclear Waste Act required that the United States government accept and permanently dispose of high-level radioactive waste and spent nuclear fuel by January 31, 1998, and it also imposed on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. SCE&G entered into a Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with the DOE in 1983. As of September 30, 2015, the federal government has not accepted any spent fuel from Summer Station Unit 1, and it remains unclear when the repository may become available. SCE&G has on-site spent nuclear fuel storage capability in its existing fuel pool until at least 2017 and is constructing a dry cask storage facility to accommodate the spent nuclear fuel output for the life of Summer Station Unit 1. SCE&G may evaluate other technology as it becomes available.

The provisions of CERCLA authorize the EPA to require the clean-up of hazardous waste sites. The state of South Carolina has similar laws. SCE&G maintains an environmental assessment program to identify and evaluate current and former operations sites that could require clean-up. In addition, regulators from the EPA and other federal or state agencies periodically notify SCE&G that it may be required to perform or participate in the investigation and remediation of a hazardous waste site. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures may differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Such amounts are recorded in regulatory assets and amortized, with recovery provided through rates.

SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals.  These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC and the EPA.  SCE&G anticipates that major remediation activities at all these sites will continue at least through 2017 and will cost an additional $19.0 million, which is accrued in Other within Deferred Credits and Other Liabilities on the condensed consolidated balance sheet.  SCE&G expects to recover any cost arising from the remediation of MGP sites through rates.  At September 30, 2015, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $34.7 million and are included in regulatory assets.

Asset Retirement Obligations

Consolidated SCE&G recognizes a liability for the present value of an ARO when incurred if the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional ARO is factored into the

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measurement of the liability when sufficient information exists, but such uncertainty is not a basis upon which to avoid liability recognition.

The legal obligations associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation relate primarily to Consolidated SCE&G’s utility operations.  As of September 30, 2015 and December 31, 2014, Consolidated SCE&G has recorded AROs of approximately $174 million and $201 million, respectively, for nuclear plant decommissioning and AROs of approximately $286 million and $335 million, respectively, for other conditional obligations primarily related to generation, transmission and distribution properties, including gas pipelines. All of the amounts recorded are based upon estimates which are subject to varying degrees of imprecision, particularly since such payments will be made many years in the future.

A reconciliation of the beginning and ending carrying amount of asset retirement obligations is as follows:

Millions of dollars	September 30, 2015			December 31, 2014
Beginning balance	$	536		$	547
Liabilities incurred	—			3
Liabilities settled	(15		)	(6		)
Accretion expense	18			25
Revisions in estimated cash flows	(79		)	(33		)
Ending balance	$	460		$	536

Revisions in estimated cash flows during 2015 primarily relate to changes in the expected timing of settlement of AROs in light of changes in the estimated useful lives of certain electric utility properties identified as part of a customary depreciation study.

10. AFFILIATED TRANSACTIONS

CGT transports natural gas to SCE&G to serve retail gas customers and certain electric generation requirements.  Prior to January 31, 2015, CGT was a wholly-owned subsidiary of SCANA, and SCE&G's transactions with CGT prior to January 31, 2015 were affiliated transactions. SCE&G's affiliated purchases from CGT totaled approximately $6.9 million for the three months ended September 30, 2014, and $3.4 million and $21.6 million for the nine months ended September 30, 2015 and 2014, respectively.  SCE&G's affiliated payables to CGT for transportation services were $3.3 million at December 31, 2014, and SCE&G's affiliated receivables from CGT related to such transportation services were $1.2 million at December 31, 2014.

SCE&G purchases natural gas and related pipeline capacity from SEMI to serve its retail gas customers and certain electric generation requirements.  Such purchases totaled approximately $34.0 million and $46.8 million for the three months ended September 30, 2015 and 2014, respectively, and $101.4 million and $154.1 million for the nine months ended September 30, 2015 and 2014, respectively.  SCE&G’s payables to SEMI for such purchases were $9.6 million at September 30, 2015 and $12.6 million at December 31, 2014.

SCE&G owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and sale of refined coal to reduce emissions. SCE&G accounts for this investment using the equity method.  SCE&G’s total purchases from this affiliate were $66.3 million and $82.4 million for the three months ended September 30, 2015 and 2014, respectively, and $186.0 million and $191.9 million for the nine months ended September 30, 2015 and 2014, respectively.  SCE&G’s total sales to this affiliate were $65.9 million and $82.0 million for the three months ended September 30, 2015 and 2014, respectively, and $185.1 million and $190.9 million for the nine months ended September 30, 2015 and 2014, respectively. SCE&G’s receivable from this affiliate was $21.6 million at September 30, 2015 and $27.8 million at December 31, 2014.  SCE&G’s payable to this affiliate was $21.8 million at September 30, 2015 and $27.9 million at December 31, 2014.

SCANA Services provides the following services to Consolidated SCE&G, which are rendered at direct or allocated cost: information systems services, telecommunications services, customer services, marketing and sales, human resources, corporate compliance, purchasing, financial services, risk management, public affairs, legal services, investor relations, gas supply and capacity management, strategic planning, general administrative services, and retirement benefits. In addition, SCANA Services processes and pays invoices for Consolidated SCE&G and is reimbursed. Costs for these services were $80.8 million and $65.0 million for the three months ended September 30, 2015 and 2014, respectively, and $226.0 million and

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$211.4 million for the nine months ended September 30, 2015 and 2014, respectively. Consolidated SCE&G's payables to SCANA Services for these services were $37.2 million at September 30, 2015 and $47.3 million at December 31, 2014.

Money pool borrowings from an affiliate are described in Note 4.

11. SEGMENT OF BUSINESS INFORMATION

Consolidated SCE&G’s reportable segments are listed in the following table.  Consolidated SCE&G uses operating income to measure profitability for its regulated operations.  Therefore, earnings available to common shareholder are not allocated to the Electric Operations and Gas Distribution segments.  Intersegment revenues were not significant.

Millions of dollars	External Revenue		Operating Income			Earnings Available to Common Shareholder
Three Months Ended September 30, 2015
Electric Operations	$	743	$	313		n/a
Gas Distribution	63		(6		)	n/a
Adjustments/Eliminations	—		—			$	164
Consolidated Total	$	806	$	307		$	164

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

Three Months Ended September 30, 2014
Electric Operations	$	740	$	274		n/a
Gas Distribution	72		(2		)	n/a
Adjustments/Eliminations	—		—			$	154
Consolidated Total	$	812	$	272		$	154

Nine Months Ended September 30, 2014
Electric Operations	$	2,032	$	616	n/a
Gas Distribution	337		40		n/a
Adjustments/Eliminations	—		—		$	374
Consolidated Total	$	2,369	$	656	$	374

Segment Assets	September 30, 2015		December 31, 2014
Electric Operations	$	10,531	$	10,182
Gas Distribution	749		721
Adjustments/Eliminations	3,032		3,204
Consolidated Total	$	14,312	$	14,107

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

SOUTH CAROLINA ELECTRIC & GAS COMPANY

The following discussion should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations appearing in SCE&G’s Annual Report on Form 10-K for the year ended December 31, 2014. 

RESULTS OF OPERATIONS

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2015

AS COMPARED TO THE CORRESPONDING PERIODS IN 2014

Net Income

Net income for Consolidated SCE&G was as follows:

	Third Quarter						Year to Date
Millions of dollars	2015		Change		2014		2015		Change		2014
Net income	$	167.4	6.7	%	$	156.9	$	404.6	5.8	%	$	382.5

Third Quarter and Year to Date

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

Dividends Declared

Consolidated SCE&G’s Boards of Directors declared the following dividends on common stock (all of which was held by SCANA) during 2015:

Declaration Date	Amount	Quarter Ended	Payment Date
February 20, 2015	$70.7 million	March 31, 2015	April 1, 2015
April 30, 2015	$69.7 million	June 30, 2015	July 1, 2015
July 30, 2015	$70.5 million	September 30, 2015	October 1, 2015
October 29, 2015	$74.5 million	December 31, 2015	January 1, 2016

Electric Operations

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

	Third Quarter						Year to Date
Millions of dollars	2015		Change		2014		2015		Change		2014
Operating revenues	$	743.6	0.4	%	$	740.4	$	2,012.7	(1.0	)%	$	2,032.7
Less: Fuel used in generation	186.7		(12.5	)%	213.3		524.8		(18.0	)%	639.9
Purchased power	14.0		6.9	%	13.1		38.3		(29.6	)%	54.4
Margin	542.9		5.6	%	514.0		1,449.6		8.3	%	1,338.4
Other operation and maintenance expenses	129.4		8.3	%	119.5		376.6		3.0	%	365.7
Depreciation and amortization	52.6		(27.2	)%	72.3		199.8		(7.6	)%	216.2
Other taxes	48.1		1.5	%	47.4		144.9		3.0	%	140.7
Operating Income	$	312.8	13.8	%	$	274.8	$	728.3	18.3	%	$	615.8

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Third Quarter

Margin increased due to base rate increases under the BLRA of $19.8 million, weather of $10.7 million and residential and commercial customer growth of $6.8 million. These increases were partially offset by lower industrial margins of $2.4 million. Margin also decreased due to downward adjustments of $14.5 million in 2015, compared to $4.4 million in 2014, pursuant to orders of the SCPSC, related to fuel cost recovery and SCE&G’s DSM Programs. These adjustments were fully offset by the recognition, within other income, of gains realized upon the late 2013 settlement of certain interest rate contracts and lower depreciation expense upon the adoption and implementation of revised depreciation rates as a result of an updated depreciation study. Operations and maintenance expenses increased due to higher labor costs of $7.4 million, primarily due to higher incentive compensation costs, incremental storm expenses of $1.4 million and the amortization of $1.5 million of DSM Programs cost. Depreciation and amortization decreased by $21.7 million in 2015 due to the implementation of the above mentioned revised depreciation rates, $14.5 million of which was offset by downward revenue adjustments. This decrease in depreciation expense was partially offset by increases associated with net plant additions. Other taxes increased due to net plant additions.

Year to Date

Margin increased due to downward adjustments of $64.6 million in 2014, compared to downward adjustments of $19.7 million in 2015, pursuant to orders of the SCPSC, related to fuel cost recovery and SCE&G’s DSM Programs. These adjustments were fully offset by the recognition, within other income, of gains realized upon the late 2013 settlement of certain interest rate contracts, lower depreciation expense upon the adoption and implementation of revised depreciation rates as a result of an updated depreciation study and the application, as a reduction to operation and maintenance expenses, of a portion of SCE&G’s storm damage reserve. Margin also increased due to base rate increases under the BLRA of $51.3 million and residential and commercial customer growth of $15.9 million. These increases were partially offset by lower industrial margins of $8.9 million and lower collections under SCE&G’s rate rider for pension costs of $3.0 million. Operations and maintenance expenses increased due to higher labor costs of $2.6 million, primarily due to higher incentive compensation costs, partially offset by lower pension costs as a result of lower rate rider collections, the application of $5.0 million in 2014 of SCE&G’s storm damage reserve to offset downward revenue adjustments related to its DSM Programs and the amortization of $2.9 million of DSM Programs cost. Depreciation and amortization decreased by $21.7 million in 2015 due to the implementation of the above mentioned revised depreciation rates, $14.5 million of which was offset by downward revenue adjustments. This decrease in depreciation expense was partially offset by increases associated with net plant additions. Other taxes increased due to net plant additions.

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

	Third Quarter				Year to Date
Classification	2015	Change		2014	2015	Change		2014
Residential	2,426	4.8	%	2,315	6,425	0.9	%	6,370
Commercial	2,143	2.0	%	2,100	5,754	1.4	%	5,676
Industrial	1,660	(0.5	)%	1,668	4,726	1.4	%	4,662
Other	165	(2.9	)%	170	458	(0.2	)%	459
Total Retail Sales	6,394	2.3	%	6,253	17,363	1.1	%	17,167
Wholesale	266	3.1	%	258	749	1.6	%	737
Total Sales	6,660	2.3	%	6,511	18,112	1.2	%	17,904

Third Quarter

Retail sales volume increased primarily due to customer growth and the effects of weather.

Year to Date

Retail sales volume increased primarily due to customer growth.

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Gas Distribution

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

	Third Quarter								Year to Date
Millions of dollars	2015			Change		2014			2015		Change		2014
Operating revenues	$	62.7		(12.7	)%	$	71.8		$	274.8	(18.4	)%	336.7
Less: Gas purchased for resale	36.7			(19.2	)%	45.4			150.8		(28.2	)%	210.1
Margin	26.0			(1.5	)%	26.4			124.0		(2.1	)%	126.6
Other operation and maintenance expenses	18.5			13.5	%	16.3			51.1		2.8	%	49.7
Depreciation and amortization	6.7			3.1	%	6.5			20.0		4.2	%	19.2
Other taxes	6.1			3.4	%	5.9			18.5		5.1	%	17.6
Operating Income (Loss)	$	(5.3	)	130.4	%	$	(2.3	)	$	34.4	(14.2	)%	$	40.1

Third Quarter and Year to Date

Margin decreased primarily due to a SCPSC-approved decrease in base rates under the RSA which became effective in November 2014. Operation and maintenance expenses increased due to higher labor costs, primarily due to higher incentive compensation costs. Depreciation and amortization and other taxes increased due to net plant additions.

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

	Third Quarter				Year to Date
Classification (in thousands)	2015	Change		2014	2015	Change		2014
Residential	695	1.3	%	686	9,320	(9.2	)%	10,266
Commercial	2,302	(2.3	)%	2,355	9,513	(6.2	)%	10,138
Industrial	4,468	—	%	4,467	13,336	(2.5	)%	13,681
Transportation	1,138	(0.6	)%	1,145	3,486	15.9	%	3,009
Total	8,603	(0.6	)%	8,653	35,655	(3.9	)%	37,094

Third Quarter

Commercial  interruptible volumes decreased due to lower average use. Residential and commercial firm sales volumes increased due to customer growth, partially offset by decreased average use. 

Year to Date

Residential and commercial firm sales volumes decreased due to the effects of weather and lower average use, partially offset by customer growth.  Commercial and industrial interruptible volumes decreased due to curtailments and lower average use.  Transportation volumes increased due to customers shifting to transportation only service.

Other Operating Expenses

Other operating expenses were as follows:

	Third Quarter						Year to Date
Millions of dollars	2015		Change		2014		2015		Change		2014
Other operation and maintenance	$	147.9	8.8	%	$	135.9	$	427.7	3.0	%	$	415.3
Depreciation and amortization	59.3		(24.7	)%	78.8		219.8		(7.0	)%	236.4
Other taxes	54.2		1.7	%	53.3		163.4		3.3	%	158.2

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Third Quarter

Operations and maintenance expenses increased due to labor of $8.9 million, primarily due to higher incentive compensation costs, incremental storm expenses of $1.4 million and due to the amortization of $1.5 million of DSM Programs cost. Depreciation and amortization decreased by $21.7 million due to the above mentioned revised depreciation rates, $14.5 million of which is offset by downward revenue adjustments. This decrease in depreciation expense was partially offset by increases associated with net plant additions. Other taxes increased due to net plant additions.

Year to Date

Operations and maintenance expenses increased due to labor of $4.2 million, primarily due to higher incentive compensation costs partially offset by lower pension costs as a result of lower rate rider collections, the application of $5.0 million in 2014 of SCE&G’s storm damage reserve to offset downward revenue adjustments related to its DSM Programs and due to the amortization of $2.9 million of DSM Programs cost. Depreciation and amortization decreased by $21.7 million due to the above mentioned revised depreciation rates, $14.5 million of which is offset by downward revenue adjustments. This decrease in depreciation expense was partially offset by increases associated with net plant additions. Other taxes increased due to net plant additions.

Other Income (Expense)

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

	Third Quarter								Year to Date
Millions of dollars	2015			Change		2014			2015			Change		2014
Other income	$	6.2		(32.6	)%	$	9.2		$	24.0		(66.3	)%	$	71.3
Other expense	(6.7		)	(2.9	)%	(6.9		)	(20.9		)	11.8	%	(18.7		)
AFC - equity funds	7.4			(22.1	)%	9.5			18.4			(17.1	)%	22.2

Third Quarter

Other income decreased due primarily to the recognition of $4.4 million of gains in 2014 realized upon the settlement of certain interest rate contracts previously recorded as regulatory liabilities pursuant to the SCPSC orders previously discussed. Such gain recognition was fully offset by downward adjustments to revenues reflected within electric margin and had no effect on net income (see electric margin discussion). AFC decreased due to lower AFC rates.

Year to Date

Other income decreased due primarily to the recognition of $59.6 million of gains in 2014, compared to $5.2 million in 2015, realized upon the settlement of certain interest rate contracts previously recorded as regulatory liabilities pursuant to the SCPSC orders previously discussed. Such gain recognition was fully offset by downward adjustments to revenues reflected within electric margin and had no effect on net income (see electric margin discussion). AFC decreased due to lower AFC rates.

Interest Expense

Interest charges increased primarily due to increased borrowings.

Income Taxes

Income taxes for the three and nine months ended September 30, 2015 were higher than the same periods in 2014 primarily due to higher income before taxes.

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LIQUIDITY AND CAPITAL RESOURCES

Consolidated SCE&G anticipates that its cash obligations will be met through internally generated funds, additional short- and long-term borrowings, and equity contributions from its parent company.  Consolidated SCE&G expects that, barring a future impairment of the capital markets, it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future, including the cash requirements for nuclear construction and refinancing maturing long-term debt.  Consolidated SCE&G’s ratio of earnings to fixed charges for the nine and 12 months ended September 30, 2015 was 4.06 and 3.77, respectively.

SCE&G received approximately $196 million, net, in equity from its parent company during the six months ended September 30, 2015.

In May 2015, SCE&G issued $500 million of 5.1% first mortgage bonds due September 1, 2065. Proceeds from this sale were used to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes.

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

At September 30, 2015, Consolidated SCE&G had net available liquidity of approximately $1.2 billion, comprised of cash on hand and available amounts under lines of credit. The credit agreements total an aggregate of $1.4 billion, of which $200 million is scheduled to expire in October 2016 and the remainder is scheduled to expire in October 2019. Consolidated SCE&G regularly monitors the commercial paper and short-term credit markets to optimize the timing of repayment of outstanding balances on its draws, if any, from the credit facilities. Consolidated SCE&G’s long term debt portfolio has a weighted average maturity of approximately 24 years at a weighted average effective interest rate of 5.8%. All of the long-term debt bears fixed interest rates or is swapped to fixed. To further preserve liquidity, Consolidated SCE&G rigorously reviews its projected capital expenditures and operating costs and adjusts them where possible without impacting safety, reliability, and core customer service.

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

SCE&G's current preliminary estimates of its capital expenditures for new nuclear construction (including transmission) for 2015 through 2017, which are subject to continuing review and adjustment, are $752 million in 2015, $1,032 million in 2016, and $959 million in 2017.

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

OTHER MATTERS

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

ITEM 4. CONTROLS AND PROCEDURES

As of September 30, 2015, SCE&G conducted an evaluation under the supervision and with the participation of its management, including its CEO and CFO, of (a) the effectiveness of the design and operation of its disclosure controls and procedures and (b) any change in its internal control over financial reporting.  Based on this evaluation, the CEO and CFO concluded that, as of September 30, 2015, SCE&G’s disclosure controls and procedures were effective.  There has been no change in SCE&G’s internal control over financial reporting during the quarter ended September 30, 2015, that has materially affected or is reasonably likely to materially affect SCE&G’s internal control over financial reporting.

65

PART II.  OTHER INFORMATION

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

SCANA:

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

Issuer Purchases of Equity Securities
	(a)	(b)		(c)	(d)
Period	Total number of shares (or units) purchased	Average price paid per share (or unit)		Total number of shares (or units) purchased as part of publicly announced plans or programs	Maximum number (or approximate dollar value) of shares (or units) that may yet be purchased under the plans or programs
July 1-31	303,960	$	52.49	303,960
August 1-31	84,191	$	55.39	84,191
September 1-30	88,042	$	52.41	88,042
Total	476,193			476,193	*

*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 once the sales of certain subsidiaries were completed. The sales of the subsidiaries were completed in the first quarter of 2015. This program has no stated maximum number of shares that may be purchased and no stated expiration date.

ITEM 5.    OTHER INFORMATION

SCANA and SCE&G:

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

ITEM 6. EXHIBITS

SCANA and SCE&G:

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

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

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SIGNATURES

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

SCANA CORPORATION

SOUTH CAROLINA ELECTRIC & GAS COMPANY

(Registrants)

	By:	/s/James E. Swan, IV
Date: November 6, 2015		James E. Swan, IV
		Controller
		(Principal accounting officer)

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EXHIBIT INDEX

	Applicable to Form 10-Q of
Exhibit No.	SCANA	SCE&G	Description
3.01	X		Restated Articles of Incorporation of SCANA, as adopted on April 26, 1989 (Filed as Exhibit 3-A to Registration Statement No. 33-49145 and incorporated by reference herein)
3.02	X		Articles of Amendment dated April 27, 1995 (Filed as Exhibit 4-B to Registration Statement No. 33-62421 and incorporated by reference herein)
3.03	X		Articles of Amendment effective April 25, 2011 (Filed as Exhibit 4.03 to Registration Statement No. 333-174796 and incorporated by reference herein)
3.04		X	Restated Articles of Incorporation of SCE&G, as adopted on December 30, 2009 (Filed as Exhibit 1 to Form 8-A (File Number 000-53860) and incorporated by reference herein)
3.05	X		By-Laws of SCANA as amended and restated as of February 19, 2009 (Filed as Exhibit 4.04 to Registration Statement No. 333-174796 and incorporated by reference herein)
3.06		X	By-Laws of SCE&G as revised and amended on February 22, 2001 (Filed as Exhibit 3.05 to Registration Statement No. 333-65460 and incorporated by reference herein)
10.01	X		Form of Indemnification Agreement (Filed as Exhibit 10.01 to Form 10-Q for the period ended June 30, 2012 and incorporated by reference herein)
10.02	X		General Release and Severance Agreement between SCANA and George J. Bullwinkel, Jr. (Filed as Exhibit 10.02 to Form 10-Q for the quarter ended March 31, 2015 and incorporated by reference herein)
10.03	X		Independent Contractor Agreement between SCANA Services, Inc. and George J. Bullwinkel, Jr. (Filed as Exhibit 10.03 to Form 10-Q for the quarter ended March 31, 2015 and incorporated by reference herein)
10.04	X		SCANA Long-Term Equity Compensation Plan effective February 19, 2015 (Filed as Exhibit 4.05 to Registration Statement No. 333-204218 and incorporated as reference herein)
10.05	X	X	Amendment to EPC Contract dated October 27, 2015 (Filed herewith)
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-10.05

Confidential Trade Secret Information - Subject to Restricted Procedures                

Exhibit 10.05

AGREEMENT

AMENDMENT TO THE ENGINEERING, PROCUREMENT AND CONSTRUCTION AGREEMENT BETWEEN SOUTH CAROLINA ELECTRIC & GAS COMPANY, FOR ITSELF AND AS AGENT FOR THE SOUTH CAROLINA PUBLIC SERVICE AUTHORITY AND A CONSORTIUM CONSISTING OF WESTINGHOUSE ELECTRIC COMPANY LLC AND STONE & WEBSTER, INC., FOR AP1000® NUCLEAR POWER PLANTS

THIS AMENDMENT (“October 2015 Amendment”) to the Engineering, Procurement and Construction Agreement dated May 23, 2008 ("EPC Agreement") for the AP1000 Power Plants at the Virgil C. Summer Nuclear Generating Station (“Project”) is entered into this 27th day of October 2015, by and between South Carolina Electric & Gas Company (“SCE&G”), for itself and as agent for the South Carolina Public Service Authority (“SCPSA”) (collectively “Owner”) and a consortium consisting of Westinghouse Electric Company LLC (“Westinghouse”) and CB&I Stone & Webster, Inc. (“Stone & Webster”) (collectively “Contractor”). Owner and Contractor may be referred to individually as a “Party” and collectively as the “Parties.”

WHEREAS, Westinghouse has represented to Owner that it intends to acquire the stock of Stone & Webster from Chicago Bridge & Iron (“CB&I”) (the “Transaction”); that CB&I will have no further involvement in the Project except for certain supply agreements; and that Westinghouse intends to hire Fluor Corporation (“Fluor”) or its affiliate(s) as a subcontracted construction manager;

In consideration of the mutual promises herein and other good and valuable consideration, the receipt and sufficiency of which the Parties acknowledge, the Parties, intending to be legally bound, stipulate and agree as follows:

1.The Parties agree that this October 2015 Amendment will be a binding obligation between Owner and Westinghouse upon the approval of the boards of directors of both Owners and the authorization of the board of SCPSA for its management to execute the necessary documentation and the execution of those documents, which shall become effective upon the consummation of the Transaction (“Effective Time”), and in the event the Transaction is not consummated by March 31, 2016, this October 2015 Amendment shall be null and void in all respects. Westinghouse shall cause its wholly owned subsidiary, Stone & Webster, to execute this October 2015 Amendment.

2. Contractor hereby grants Owner until November 1, 2016 (“Option Deadline”), the irrevocable option to exercise an agreement, subject to regulatory approvals, to amend the EPC Agreement by revising the Contract Price and other specific aspects of the EPC Agreement, as stated in the amendment that is attached as Exhibit D (“Option Amendment”). Contemporaneously with the execution of this October 2015 Amendment, Contractor will execute the Option Amendment. Thereafter, Owner may, in its sole discretion, implement the Option Amendment by executing it at any time on or before the Option Deadline. The Option Amendment will not take effect unless and until Owner executes the Option Amendment, before

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the Option Deadline, and all conditions precedent to effectiveness stated in the Option Amendment are satisfied or waived by Owner.

3. Owner agrees to pay Contractor the total sum of $300,000,000 (current year U.S. Dollars) and increase the Fixed Price Contract Price by said amount. Further, Contractor agrees to provide Owner with a credit to the Target Price in the amount of $50,000,000 (current year U.S. Dollars). The net $250,000,000 will be paid in twelve equal monthly installments beginning five days after the Effective Time. In exchange, Owner and Contractor agree to a full resolution by settlement and release of any and all disputes outstanding under the EPC Agreement or otherwise concerning the Project as of the Effective Time, including the following:

a.Contractor claims for additional payments for any of the items on Exhibit A, as well as claims for additional payment for cyber security and the site layout phase 2 Change Order (Change Order 26).

b.Contractor claims for amounts referenced in letters no. VSP _ VSG_003111, VSP _ VSG_003115, VSP _ VSG_ 3145, VSP _ VSG_3502 and VSP _ VSG_3522, which totaled approximately $83,518,046 as of August 21, 2015, as set forth on Exhibit B.

c.Contractor claims for amounts in other cases in which the entitlement is in dispute, which totaled approximately $29,729,785 as of August 31, 2015, as set forth on Exhibit B.

d.Contractor claims for amounts in dispute due to billings that have been held because a Change Order has not been executed, which totaled approximately $5,565,845 as of August 31, 2015, as set forth on Exhibit B.

e.Contractor claims for all amounts in dispute in cases in which only the timing is disputed, which totaled approximately $110,190,504 as of August 31, 2015, as set forth on Exhibit B.

f.Contractor claims for the balance of 10% withheld by Owner in connection with certain invoices for which the Owner has only paid 90% because the Owner disputed the invoice

g.Owner claims for refunds in connection with invoiced amounts for which Owner has paid 90% of the invoiced amount and for which Owner had previously intended to seek a refund.

h.Owner claims arising out of the employee fuel expense audit and procurement irregularities.

Subparagraphs a through h do not provide an exhaustive list of all claims, disputes, and amounts that are satisfied by this October 2015 Amendment, it being the Parties’ intent that all disputes outstanding under the EPC Agreement or concerning the Project as of the Effective Time are settled and resolved. By way of further clarifications, under this October 2015 Amendment, the Parties waive and settle any and all claims currently pending or threatened by either Party against the other Party and of any and all claims currently known or reasonably foreseeable by either Party against the other Party. Whether or not the Option Amendment becomes effective, all pending Change Orders, and formal and informal notices of potential Change Orders, including but not limited to those arising from Uncontrollable Circumstances and Changes in Law, are

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hereby settled and resolved. Each Party represents and warrants to the other Party that it is not aware of the basis for any other claim against the other, including but not limited to those arising from Uncontrollable Circumstances and Changes in Law, and that it is not aware of any facts or circumstances that could be expected to give rise to a claim, the sole exceptions being those claims addressed in paragraph 4. For the avoidance of doubt, in the event that the Option Amendment becomes effective, the $300,000,000 payment and the $50,000,000 credit to the Target Price set forth in this paragraph 3 will be part of (and not in addition to) the total Fixed Price amount of $6.082 billion set forth in the Option Amendment.

The Parties shall execute a mutual release effectuating the provisions of this paragraph 3.

4.Notwithstanding the foregoing, the Parties have identified on Exhibit C to this Amendment all work items that they contend are required or contemplated for the Project but that are not included within the release contained in paragraph 3. Said work items are not resolved, settled or released under this October 2015 Amendment. The Parties shall cooperate in good faith to resolve all such work items expeditiously so as to not impact the Project. In the event a work item cannot be resolved, it shall be submitted to the Dispute Resolution Board as referenced in paragraphs 13 and 16. Similarly, with respect to the cyber security item listed in Exhibit A, the Parties shall cooperate in good faith to resolve all issues relating to scope expeditiously. Contractor acknowledges its obligation to commence and continue work in compliance with current NRC regulations on cyber security, pending issuance of a Change Order, so as not to impact the Project schedule, and its obligation to complete the Cyber Security work within the GSCDs stated in paragraph 6In the event a scope item cannot be resolved, it shall be submitted to the Dispute Resolution Board as referenced in paragraphs 13 and 16. Except for the items on Exhibit C and the Time and Material Work set forth in paragraph 2 of the Option Agreement, the cyber security item listed in Exhibit A and without waiving its rights concerning unknown Changes under Article 9 of the EPC Agreement, Contractor is not aware of any additions to the Scope of Work that will be required for the Project to reach Substantial Completion.

5.The Contractor acknowledges and agrees that its Scope of Work includes providing Owner with a Facility that meets the standards of DCD Rev. 19.

6.The Guaranteed Substantial Completion Dates (“GSCDs”) are revised, as follows: August 31, 2019 for Unit 2 and August 31, 2020 for Unit 3. The Standard Equipment Warranty Period(s) and the Services Warranty Period(s) shall commence upon Substantial Completion of each Unit at no additional cost to Owner. To the extent a Change under Article 9 of the EPC Agreement adversely affects Contractor’s ability to achieve Substantial Completion as provided in this paragraph 6, Contractor shall be entitled to equitable adjustment of the EPC Agreement as appropriate.

7.Section 13.1 of the EPC Agreement is revised to state that Delay Liquidated Damages for each Unit will commence on the applicable GSCDs stated in paragraph7, and will be computed as follows:

a.     For the first thirty (30) days following the GSCD: $200,000/day; and

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Confidential Trade Secret Information - Subject to Restricted Procedures                

b.     For the next thirty-one (31) to ninety (90) days: $300,000/day; and

c.         For the next ninety-one (91) to one hundred fifty (150) days: $ 400,000/day; and

d. For the next one hundred fifty-one (151) to seven hundred thirty (730) days: $500,000/day; and

e.     Seven hundred thirty-one (731) days or beyond: $0/day.

8.The Parties agree to share the loss if either or both Units do not qualify for production tax credits under Federal law. If a Unit is not “placed in service,” as that term is used in Section 45J of the Internal Revenue Code, before January 1, 2021, Contractor agrees to reimburse Owner by February 1, 2021, the sum of $250 million per Unit, expressed as a one-time lump sum payment. For purposes of this paragraph, the January 1, 2021 date can only be extended for the following reasons (i) material actions or omissions of Owner that cause a Unit not to qualify for tax credits; or (ii) extension of the tax credit date by the U.S. government. If Contractor becomes aware of any actions or omissions of Owner that Contractor believes may cause a Unit not to qualify for tax credits, Contractor shall provide Owner with reasonable notice of such actions or omissions.

9.The maximum amount paid by Contractor to Owner under paragraphs 7 and 8 above will be limited to $338 million per Unit, if the Option Amendment becomes effective. In the event the Option Amendment does not become effective, the maximum amount paid by Contractor to Owner under paragraphs 7 and 8 above will be limited to $463 million per Unit.

10.Owner will pay Contractor an early completion bonus consisting of $150,000,000 per Unit for each Unit that is “placed in service,” as that term is used in Section 45J of the Internal Revenue Code, in advance of January 1, 2021, if the Option Amendment becomes effective. In the event the Option Amendment does not become effective, Owner will pay Contractor an early completion bonus consisting of $275,000,000 per Unit for each Unit that is “placed in service,” as that term is used in Section 45J of the Internal Revenue Code, in advance of January 1, 2021. For purposes of this paragraph, the January 1, 2021 date can only be extended for the following reasons (i) material actions or omissions of Owner that cause a Unit not to qualify for tax credits; or (ii) extension of the tax credit date by the U.S. government. If Contractor become aware of any actions or omissions of Owner that Contractor believes may cause a Unit not to qualify for tax credits, Contractor shall provide Owner with reasonable notice of such actions or omissions.

11.The Parties agree that no new Inspection, Tests, Analyses and Acceptance Criteria (“ITAACs”) have been issued or proposed as of the Effective Time that would affect the GCSDs or entitle the Contractor to a Change Order.

12.The Parties shall cooperate in good faith to develop a new milestone payment schedule (“Construction Milestone Payment Schedule”) to include all unpaid or overpaid amounts. While such good faith efforts are ongoing, Owner agrees to make payments to Contractor in the amount of $100,000,000 per month for the first five (5) months following the Effective Time. Said payments shall be in lieu of all payments for Fixed Price, Firm Price, Target Price and Time and Material Work. Once developed, Contractor agrees that Owner is to make such payments to Contractor according to the Construction Milestone Payment Schedule, instead of the existing Payment Schedules. If the Parties fail to agree to a Construction Milestone Payment Schedule by the date that is six months from the Effective Time, the matter shall be referred to the Dispute

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Resolution Board (“DRB”) process for resolution. Unless otherwise agreed by the Parties, the DRB shall issue its report on the Construction Milestone Payment Schedule within sixty (60) days. For the 60 day period during which the DRB is reviewing the Construction Milestone Payment Schedule, Owner shall pay the sum of $100,000,000 per month in lieu of all other payments, and such payments will be treated in the same manner as the payments referenced in paragraph 3.

Contractor will continue to invoice Owner according to previous procedures (i.e. Contractor will provide parallel invoices for Target, T&M, and Firm and Fixed Price categories) to enable calculation of the amount by which the payments described in paragraphs 3 and 12 exceed what would otherwise be due Contractor. After these advance payments cease, the excess or deficit portion of such advance payments shall be adjusted against future invoices submitted by Contractor to Owner under the EPC Agreement, at the Owner’s sole discretion. Actual payments will be trued up to parallel invoices in months 6, 12 or when the Option Amendment becomes effective.

In the event that the Option Amendment is exercised and takes effect, the actual payments made under paragraphs 3 and 12 will be deducted from the amount referenced in section 1 of the Option Amendment. If the Option Amendment does not take effect, billing procedures for Target and T&M Work scopes will revert back to the EPC Agreement terms, as amended, incorporating the adjusted terms in paragraph 3 above, and Firm Price and Fixed Price scopes will continue to be billed based on the Construction Milestone Payment Schedule. For the avoidance of doubt, the cash flows of the Construction Milestone Payment Schedule will be reduced to reflect the lower amounts remaining in the Fixed Price and Firm Price categories as defined in Exhibit H of the EPC Agreement.

13.Within ten (10) days of establishing the Construction Milestone Payment Schedule, Owner shall advance a deposit of seventy-five million dollars ($75,000,000) with the Contractor.

a. After the deposit is made, Owners will not be obligated to pay to Contractor the disputed portion of any invoiced amounts submitted by Contractor to Owners.

b. The Parties shall revise the dispute resolution procedures in Article 27 of the EPC Agreement to eliminate the requirement or ability to institute litigation during the course of the Project absent a suspension or termination of the EPC Agreement.

c. The Parties shall establish a DRB process for the interim, non-final resolution of disputes, as described more fully in paragraph 16 below and Exhibit E.

d. Owner agrees to make payment to Contractor within thirty (30) days of any award entered in favor of Contractor by the DRB.

e. At Project completion, the deposit amount of $75,000,000 shall be credited against Owner’s final milestone payment owed Contractor.

14.The definition of “Change in Law” in the EPC Agreement is modified so that a Change in Law occurs only in case of (a) the formal written adoption by a Government Authority of a new statute, regulation, requirement or code that did not exist as of the date of the October 2015 Amendment; or (b) where the NRC is the involved Government Authority, the NRC’s official issuance or promulgation, after the date of the October 2015 Amendment, of a final and official

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Confidential Trade Secret Information - Subject to Restricted Procedures                

version of Regulatory Guides (NUREGs), Branch Technical Positions, Standard Review Plans, Interim Staff Guidance, Bulletins, Orders, or written directives, in which NRC acknowledges a new regulatory requirement or a change to an existing requirement that did not apply before the date of the October 2015 Amendment. Where Contractor cannot demonstrate a Change in Law under this paragraph, Contractor shall also be precluded from claiming that the purported Change in Law is an Uncontrollable Circumstance.

15.The Parties agree to participate in meetings with the Nuclear Regulatory Commission ("NRC") and develop strategies in an effort to alleviate issues that have arisen due to the NRC's inspections at the Project, while still affording the NRC the ability to conduct appropriate inspections. Owner cannot agree in advance to adopt the Contractor’s position on every issue, but Owner will work with Contractor in good faith. In the event the Option becomes effective, Owner shall have no obligation to pay Contractor for regulatory support associated with License Amendment Requests or ITAACs, except those that arise due to a Change. In the event the Option Amendment does not become effective, such matters shall be submitted to the DRB process established pursuant to this October 2015 Amendment. For the period of time between the Effective Time and the Option Deadline, the Parties agree to suspend the DRB process for matters relating to regulatory support associated with License Amendment Requests and ITAACs. In the event the Option Amendment does not become effective, the suspended DRB matters will be administered. If the Option becomes effective, those matters suspended by the preceding sentence shall be deemed to be included in the Fixed Price.

16.Consistent with paragraph 13 above, Article 27 of the EPC Agreement is revised to eliminate the requirement or ability to bring suit during the course of the Project. The Parties agree to empanel a DRB for the interim, non-final resolution of disputes in accordance with the Dispute Resolution Agreement that is attached as Exhibit E.

17.Owner hereby waives and cancels the Chicago Bridge & Iron Parent Company Guaranty. Owner agrees that Contractor shall be relieved of any obligation to furnish a parent company guaranty on behalf of S&W under the EPC Agreement. Owner and CB&I shall execute a mutual release of all claims relating to the EPC Agreement, the Project, the S&W Parent Guarantee and the CB&I Guarantee.

18.The Parties agree to hold a face-to-face meeting among Owner, Westinghouse, the President and Chief Executive Officer of Power Systems Company, and Mr. Shiga Shigenori, the Representative Executive Officer and Corporate Senior Executive Vice President of Toshiba Corporation (or his successor) to allow Owner to describe its concerns with the Project to date and to discuss Toshiba's commitment to completing the Project and to the terms of this Agreement. In addition, at Owner’s option, Toshiba, Owner, Contractor, and Fluor will hold quarterly meetings to discuss Project progress.

19.Contractor's profit on any future Change Orders under the EPC Agreement shall be capped at 7 ¾%.

20.The Parties agree that Article 13.3 is deleted from the EPC Agreement.

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21.The provisions of Section 8.6(d) of the EPC Agreement are revised to provide that SCE&G or Santee Cooper shall not be required to furnish Contractor with an irrevocable, standby letter of credit, provided the Credit Rating of SCE&G or Santee Cooper, as applicable, remains at or above investment grade (Standard and Poor’s BBB-; Moody’s Baa3). If the Credit Rating of SCE&G or Santee Cooper falls below investment grade, Contractor may request the letter of credit, and SCE&G or Santee Cooper must furnish the letter of credit at no expense to Contractor.

22.The Parties agree to cooperate with respect to the involvement of Owner’s Project consultant and/or Owner’s Engineer with the work scheduled to be done by Owner’s consultant.

a. Contractor shall carefully consider all matters raised by the consultant, however the consultant shall have no authority to direct the Work of Contactor.

b. Contractor agrees to provide the consultant with access to relevant documents reasonably requested bythe consultant, provided such documents are necessary for the consultant to complete its work for Owners.

c. For relevant documents provided under subparagraph (b) above, Contractor may provide confidential and proprietary documents in redacted form, including redaction of any pricing information. Contractor will provide unredacted documents to the consultant, provided Contractor determines in its reasonable discretion that it is given suitable protections from Owners and/or the consultant against misuse or further disclosure of such documents.

23.Contractor acknowledges Owner’s right to discuss any and all operational and project execution issues with the Vogtle owners. Owner is not permitted to disclose to the Vogtle owners information relating to any disputes, commercial issues or the terms and conditions of this agreement and any related documents or agreements.

24.All capitalized terms in this October 2015 Amendment, except for those defined in this October 2015 Amendment, shall have the meanings given to them in the EPC Agreement.

25.All provisions of the EPC Agreement not modified, expressly or by necessary implication, remain in full force and effect. All Exhibit references are to this October 2015 Amendment.

26.While the Parties acknowledge the existence of various confidentiality agreements between themselves, they also recognize that certain disclosures must be made to satisfy various securities laws and for regulatory purposes. Each Party is free to make such disclosures as it deems prudent, but the disclosing Party must provide a copy of any intended written disclosure to the other Parties before such disclosure is made.

27.Upon execution of this October 2015 Amendment, Contractor will provide written details of its relationship and structure with Fluor, including a scope of work description, sufficient to allow the Owner to understand the roles and responsibilities of Fluor on the Project. In the event of a material change in the relationship, structure, or scope, Contractor will provide details of the

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change. In the event the Option Amendment does not become effective, Contractor shall submit construction related billings consistent with the existing provisions of the EPC Agreement.

28.To the extent not prohibited by its existing contracts, Contractor agrees to afford Owner and Owner’s consultant access to its facilities and those of its suppliers and subcontractors at any tier, for the purpose of completing Owner’s consultant’s assessment and monitoring of the Project and the Project Schedule.

29.In the form of Exhibit F, Contractors will provide written consent of Toshiba Corporation to this October 2015 Agreement, affirming that the corporate guaranty of Toshiba remains in place, notwithstanding this October 2015 Agreement. This signed exhibit must be provided to Owner’s prior to the Effective Time.

[Balance of Page Intentionally Blank]

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IN WITNESS WHEREOF, the Parties have duly executed this October 2015 Amendment to the EPC Agreement as of the date first above written, with Toshiba Corporation, as the parent corporation of Westinghouse, indicating its express consent hereto.

SOUTH CAROLINA ELECTRIC & GAS

COMPANY, for itself and as agent for South

Carolina Public Service Authority

By:	/s/Kevin B. Marsh
Name:	Kevin B. Marsh
Title:	Chairman & CEO

WESTINGHOUSE ELECTRIC COMPANY LLC		STONE & WEBSTER, INC.
By:	/s/Danny Roderick	By:
Name:	Danny Roderick	Name:
Title:	President & Chief Executive Officer	Title:

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Exhibit A
Count	Issue	Issue Description	Deliverable
29	CAS and PRS Support	Primarily due to delayed design completion, the simulators delivered by the Consortium (intended to be PRSs) to the Owner do not have the functionality to support being certified by the Nuclear Regulatory Commission. As a result, the Owner has had to pursue the CAS alternative due primarily to repeated delays in ISV testing by the Consortium, which have most recently impacted the completion of ISV testing in time to support the Owner NRC exams that had been scheduled to occur in May 2015. This issue puts at risk the Owner’s ability to train and certify operators in time to support Units 2 and 3 fuel loads.	(1) At no additional cost to Owner, Westinghouse to provide a Commission Approved Simulator to include: All fixes as identified to support a successful CAS implementation (fixes delivered, support to install, and fixes to fixes as necessary); End state deliverable is a simulator ready and capable of conducting license operator exams (2) If CAS is unsuccessful, at no additional cost to Owner, WEC to provide: All ISV/HEDs (Priority 1 and 2 ) fixed and included in a baseline 7+ simulator capable of closing the ISV ITAAC by June 2017; The HFE/ISV ITAAC should be closed such that we can answer the question in the NRC Inspection Procedure IP41502 for PRS “Is the ISV ITAAC closed?” Yes; The simulator must be delivered to site by June 2017; Success will be measured by successful completion of Inspection Procedure 41502 by NRC Region II resulting in us having a PRS (3) If CAS is successful, at no additional cost to Owner, Westinghouse to provide: All ISV/HEDs (Priority 1 and 2 ) fixed and included in a baseline 8 simulator capable of closing the ISV ITAAC by Mar 2018; The HFE/ISV ITAAC should be closed such that we can answer the question in the NRC Inspection Procedure IP41502 for PRS “Is the ISV ITAAC closed?” Yes; The simulator must be delivered to site by March 2018; Success will be measured by successful completion of Inspection Procedure 41502 by NRC Region II resulting in us having a PRS. (4) Commercially, CAS, CAS fixes and BL7+ ITAAC closure (if necessary) is all part of completion of ISV and delivery of a BL7 simulator and as such is already a paid for deliverable. As part of that, the BL8 Fuel Load baseline should be considered the deliverable for CO #19.
30	Design Basis Assessments (5 included in the scope)	Licensing and Regulatory compliance reviews of high risk portions of the AP1000 design is to uncover License and Regulatory noncompliance issues prior to Construction to preclude delays to Project completion similar to those encountered during construction of the Nuclear Island basemat in 2012. The results of these reviews have uncovered License noncompliance issues including Tier 1 and Tier 2* issues and successfully mitigated them through a Licensing or design change without adverse impact to the Project schedules. It is likely that these items would not have been uncovered prior to Construction without the undertaking of these reviews. It is also likely that, if these items were uncovered after Construction had commenced, work delays of multiple months would have been experienced while the issues were resolved. Westinghouse contends that the AP1000 design is consistent with all requirements of the Licensing Basis and that assessments are unnecessary. Westinghouse has charged the Owners for support necessary to perform the assessments citing that no assessments were necessary. SCE&G believes that the value of the assessments to the Projects and to Westinghouse have been demonstrated. In addition to the benefits of reduced schedule and regulatory risk mentioned above, Westinghouse receives the benefit of independent assessment of key areas of the AP1000s unique design.	SCE&G requests that Westinghouse move forward with assessments (five additional assessments are desired) and cover their internal costs such that each Party participating in the review is responsible for its own cost. In this manner, each Party shares in the costs and benefits through reduced Project schedule risk and reduced regulatory risk.
31	WEC home office and site licensing efforts	For Contractor initiated Design Changes, processing Contractor’s desired changes to the design and licensing basis is resource intensive. The Contractor has initiated and processed thousands of DCPs and hundreds of LCPs. Changes are made at the request of the Contractor for convenience or in order to address challenges within the Contractor’s original design that was purchased by the Owner under the EPC Agreement. The Owner has incurred considerable cost to process Contractor’s desired changes to the VCS 2/3 licensing basis. Such changes are made for the Contractor’s convenience. The EPC did not account for the changes to the licensing basis requested by the Contractor. The EPC was based on Owner purchase of a design from the Contractor and the Owner has incurred costs to allocate resources and obtain additional contract assistance in order to support Contractor requested changes. In addition, Contractor has requested reimbursement of expenses for implementing changes to the extent that work relates to site-specific Tier 1, Tier 2*, COL, or Tech Spec requirements. An example is the EP ITAAC Table 7.5-1 and 7.5-201 in COL Appendix C. These tables were cited by the NRC as an EP ITAAC to show required plant equipment to support EP. This equipment was also described in the DCD and if changed by the Contractor requires a site specific supporting change to the COL.	Subject to Paragraph 15 of the October 2105 Amendment, Westinghouse should be responsible for its costs incurred to make changes to the Owner’s Current Licensing Basis (CLB), attributable to its DCPs and LCPs. This includes efforts to resolve Owner comments prior to incorporation of change into the VCS 2/3 CLB, whether made on a draft or final revision of the proposed change package. It is reasonable to expect that some changes may require multiple comment review cycles due complexity and number of parties involved. Westinghouse should also be responsible for its costs incurred for implementing changes to the extent that work relates to site-specific Tier 1, Tier 2*, COL or Tech Spec requirements. The Owner will be responsible for Owner-directed changes.
32	WEC’s position on CB&I Service claim against WEC for CV costs (delay and other)	CB&I Services (WEC’s subcontractor) Containment Vessel safety-related Work was delayed from January 19, 2011 through July 31, 2011. WEC invoiced the Owner $1,405,811.35 (Target Price). CB&I Services’ work was delayed due to CB&I Services’ ineffective QA program; Westinghouse and its subcontractors are required to have a QA program that meets the requirements of the EPC Agreement. The Owner should not be liable for any charges associated with a delay period during which CB&I Services had to take actions necessary to meet its contractual QA program obligations.	WEC should retract this invoice as no longer owed by the Owner. Whatever settlement WEC reached with CB&I Services associated with this delay should remain between WEC and its subcontractor. No further invoices will be issued to Owner related to the costs for schedule delay impacts on the CV unless related to a Change under Article 9 of the EPC Agreement.
33	Secondary Lab and Sampling Room in Turbine Building	Per Exhibit A of the EPC Agreement, the Turbine Building is to be provided as a complete structure and finishes inclusive of all equipment, components and commodities. Consortium's position is that they are entitled to a Change Order for the completion of Secondary Chemistry Laboratory including utilities (e.g. gas lines, water lines, faucets, drain lines, electrical outlets) and fixtures (e.g. sampling panels, fume hood, sinks, high purity water treatment unit) to be located in the laboratory that interface with multiple plant systems including the Main AC power System, Waste Water System, Potable Water System, Demineralized Water System, and the Turbine Building Ventilation System.	The Consortium should supply the secondary chemistry lab furnished to the scope of supply outlined in the attachment titled “Secondary Chemistry Lab Scope of Supply” attached to SCE&G letter NND-15-0085 dated February 4, 2015.

34	Site inspections and Vendor Inspections by NRC	For site inspections performed by the NRC, because the Contractor is responsible for design, construction, and testing of the AP1000 and maintains responsibility for the Facility Information during construction, the Contractor is obligated to provide knowledgeable personnel to support NRC inspections associated with design, construction and testing. These personnel may include subject matter experts whose work location is off site. From time to time, certain inspections may be generic in nature or rely solely on software/services. For these inspections it may be most effective, for all parties, to execute the inspection at the specific Contractor work location. This location may be off site at a contractor facility. For inspections performed by the NRC at Contractor's vendor facilities, it is the Owner’s reasonable expectation that the Contractor and Contractor’s vendors retain responsibility of Vendor inspection support. There has been no Change in Law since agreement of EPC. In fact, the NRC specifically identified their intended vendor inspection activities to include ITAAC on 6/27/2007 through SECY-07-0105. The inspections performed at vendors assure compliance with Appendix B and 10CFR21 as required by procurement documents. These inspections are not intended to confirm ITAACs but to ensure the associated QA activities are implemented in accordance with Appendix B.	At no additional cost to Owner, Westinghouse to provide the Owner with all information requested by NRC inspectors and any information requested by the Owner to properly prepare for the inspection, in addition to routine oversight. Westinghouse will need to coordinate with their vendors, as needed, to address NRC questions related to ITAAC associated activities performed by vendors or sub-vendors. For any NRC violations requiring licensee response, related to work activities within Contractor scope, the Contractor will provide information to Owner as requested by Owner to respond and address the violation. Depending on significance, these activities may require additional engineering effort or re-work in the field. For Conditions Adverse to Quality (CAQ) which have been evaluated for 10 CFR 50.55(e) reportability or are associated with an NRC Finding, the Contractor is obligated to provide any Causal Analysis which has been performed for Owner review to support any follow up. The NRC expectation is that in accordance with 10 CFR 52.99, the Owner considers vendor inspection findings during ITAAC closure. As such, the Owner expects Contractor to share information pertaining to vendor/contractor notices of nonconformance identified by NRC and their resolution to support ITAAC closure. It is also reasonable that the Contractor share inspection results with the Owner after inspection exit to ensure the Owner can capture any issues potentially affecting ITAAC into the Corrective Action Program in a timely manner. Finally, the nature of the standard plant design obliges the Contractor to successfully manage NRC vendor inspections to support construction and operation of the first AP 1000 plants.
35	ID/labeling of subcomponents	Labeling of the plant is a Consortium (construction) responsibility as outlined in the Agreement, related Project Execution Plans, and other related Project documents. In accordance with Exhibit A.2, titled "Phase II," of the Agreement, the Consortium is to provide the Owner with "one (1) or two (2) complete AP1OOO Nuclear Power Plant Units ...except for those items listed in Table 1 as Owner's Responsibility." This section further describes the AP1000 Nuclear Power Plant Units as the Standard Plant description as described in Revision 16 of the AP1000 Design Control Document (DCD). Section 18.8.4.1.9 of Revision 16 of the AP1000 DCD, titled "Coding and Labeling, states the following as it relates to labeling of components: “Equipment located in the AP1000 has a unique identifier and plant descriptive name. The configuration management system includes the identification of the equipment in the plant. Each component is assigned an identifier during the design process. The identifier is maintained through manufacturing, construction, and operation. The components are labeled according to the assigned identifier. These labels help avoid errors in operating or working on the wrong equipment and in reporting problems or conditions observed in the plant. The labels help reduce the training burden for operating and maintenance personnel. Color, syntax, abbreviations and symbols are consistently applied. The labels are located in an easily visible location on the component and are not hidden by insulation, equipment covers, or surrounding equipment. Labels are fastened to the component to prevent easy detachment of the label." APP-GW-GZP-002, "AP1000 Component Identification Labeling Procedure" contains guidance for Project groups to use in developing and affixing component identification and operator aid labels. This document lays out roles and responsibilities, label content, label material, and label placement. This procedure has been reviewed and endorsed by the Owner as an acceptable method for labeling the AP1000 Plant. Further review of the Project Execution Plans for System Turnover (APP- GW-GBH-350, Rev. 0) indicate that all system tagging labeling installation is a pre-requisite responsibility of Construction prior to turnover to Pre-Operational Testing. This approach is consistent with the expectations of SCE&G for system turnover and collaboration of station personnel in the testing and startup activities. In addition, it is the Owner’s understanding that the current Work In Progress (WIP) MELs exclude the following equipment types and are not anticipated to be numbered or labeled (note: this list is not comprehensive): Subcomponents to skids and packages; Components within I&C and Electrical Cabinets (breakers, switches, and etc.); Fuses (Master Fuse List required per UFSAR); Pipe Hangers/Snubbers; Electrical equipment controls (i.e., solenoid valves for equipment).	Consortium to provide a plan outlining the labeling of the V.C. Summer AP1000 Nuclear Power Plant. At no additional cost to Owner, Consortium to label the V.C. Summer AP1000 Units 2 and 3 in accordance with APP-GW-GZP-002.
36	FPOT/F3POT	The Owner’s position is that the Consortium is responsible for all testing in accordance with Article 11 of the EPC Agreement. This testing includes the First Plant Only Test (FPOT) and the First Three Plants Only (F3POT). The Owner acknowledges that the Consortium made an effort to take credit for the China FPOT and F3POT and results, but that the NRC was not supportive of this approach. As a result, the Consortium has incorporated the FPOT and F3POT into the testing program and schedule to be performed on site for the Units. The Owner agrees with including this testing in the T&M scope of work in the EPC Agreement, but does not agree that this testing is outside the EPC Agreement scope and warrants a change order. The Consortium and Owner positions are included in VSP_VSG_002399 and NND-13-0486, respectively.	The Consortium to perform the FPOT and F3POT as part of the testing program in accordance with Article 11 of the EPC Agreement.
37	Timely access to vendor technical manuals.	The Owner needs information turnover to develop the programs, processes and procedures to operate the plant. Furthermore, the Owner needs those documents produced and delivered in a timely fashion to facilitate the proper level of Owner review and acceptance. To date, the flow of engineering information not directly used to build the plant, i.e. placed in ShawDocs, has been insufficient. The EPC references in a number of locations that the Consortium will provide various documentation to the Owner prior to system turnover. Section A.2 states that “Documentation to be provided by the Contractor to the Owner as developed for the Facility as listed in Table. 2” and section 3.3.3 states “Contractor shall provide to Owner the necessary inputs, test procedures, technical manuals, and other Documentation related to forgoing tests.” The Owner interprets these statements to mean that as the documents are developed to a revision 0 product, they will be made available to the owner via ShawDocs or CAPA.	As the documents are developed (revision 0), at no additional cost to Owner, Westinghouse to make those documents available for Owner review. For example, if the RCS system design is complete, those documents, to include vendor technical manuals, should all be available for owner review and acceptance, well before the system testing has begun. This process should begin immediately.
38	BEACON	The WEC AP1000 reactor Standard Plant design contains a core power distribution measurement system designated as the Incore Instrumentation System (IIS). The AP1000 has been designed to use the BEACON system as part of its required control system. BEACON is an advanced core monitoring and support package. According to DCD Revision 16, this online core monitoring system provides the operator with the current allowable operating space, detailed current power distribution information, thermal margin assessment and operational recommendations to manage and maintain required thermal margins. It is understood that the AP1000 Standard Plant initial startup cannot occur without BEACON hardware and software and, as the AP1000 is designed, it cannot be operated without BEACON. In addition, per the Agreement, WEC is obligated to provide to Owner an AP1000 Standard Plant as described in DCD Revision 16. For the IIS, the system is to be supplied complete and inclusive of all equipment, components and commodities including any specialty handling tools and equipment as described in the DCD.	WEC to provide BEACON-DMM hardware and software to support fuel load, startup testing and operations as part of the EPC Agreement and without additional charge to the Owner.

Confidential Trade Secret Information - Subject to Restricted Procedures                

39	Shield Building Door, Annex, Auxiliary Building, Aircraft Impact Assessment.	The Consortium sent to Owner Notice of Change letters (VSP_VSG_003096 and VSP_VSG_003450) claiming that a new NRC Rule entitled “Consideration of Aircraft Impact for New Nuclear Power Reactors” (the AIA Rule) impacts other structures in the Nuclear Island. Specifically, the Consortium claims that it is required to make changes to the Annex and Auxiliary Buildings’ wall design, as well as Annex and Auxiliary and Shield Building doors to comply with the NRC Rule. The Consortium further claims that this scope of work is outside that of the EPC Agreement and warrants a change order. The Owner has taken exception to the Consortium claim in NND-15-0007 and NND-15-0323 based on the availability and knowledge of the draft AIA Rule prior to execution of the EPC Agreement and the comprehensive Agreement between the Consortium and the Owner executed on July 11, 2012 and resolving all issues associated with the AIA Rule impact.	Consortium to implement the necessary design and construction changes to the Shield Building Door and Annex and Auxiliary Buildings impacted by the AIA Rule in accordance with the EPC Agreement and July 11, 2012 Agreement
40	Loss of Large Areas of the Plant due to Explosions or Fire Testing	On March 27, 2009, the NRC amended 10 CFR Part 50 and 10 CFR Part 52 with new requirements to address loss of large areas (LOLAs) of the plant due to explosions or fires from a Beyond Design Basis Event. The NRC issued Interim Staff Guidance DCD/COL-ISG-016 to assist new applicants or holders of COLs to address the LOLA requirements. These requirements were not included in DCD Revision 16, which is the design basis for the Agreement (Reference 1). In Reference 2, Owner notified the NRC that changes would be made to a future revision of the V.C. Summer Units 2 & 3 COLA in accordance with 10 CFR 52.80(d) and 10 CFR 50.54(hh)(2) to address LOLA. Owner provided the NRC with a Mitigative Strategies Description (MSD), which described the preoperational testing required to provide a reasonable confirmation of adequate spent fuel pool spray coverage. These requirements were incorporated into Owner’s COL Section 2.D.(12).(e).8 as a license condition. The Consortium has offered to perform this work for SCE&G as a change order.	Consortium to perform the testing and other work required to meet Owner’s LOLA obligations under the COL Section 2.D.(12).(e).8 as a license condition at no additional cost to Owner.
41	Pre-Service Testing Program Development, Pre-Service Test Conduct, ITP	The Owner and Consortium have a difference of opinion on the Initial Test Program scope as related to the following items referenced in VSP_VSG_003669: 1. Pre-service testing, including baseline in-service testing 2. Initial core load and post core load vessel assembly 3. Any spent fuel pool spray flow and makeup testing required to support the Loss of Large Area (LOLA) Mitigation Strategy Document (reference item 40 on Commercial List) 4. Cooling Towers testing 5. Preoperational testing for: a. Storm Drains; b. Site-specific Seismic Monitoring System; c. Offsite AC Power Systems; d. Raw Water System; e. Sanitary Drain System; f. Fire Brigade Support Equipment; g. Portable Personnel Monitors and Radiation Survey Instruments; h. Physical Security Plan equipment implied in UFSAR Section 14.4.5; and, i. External/Offsite Communications The Consortiums position is that these items are not included in the EPC Agreement scope. The Owner’s position is that the items above are in the EPC Agreement ITP scope. Additional ITP expectations include the following: 1. All FPOT and F3POT testing and associated activities to include test specification and procedure development, material/equipment procurement, test planning, test scheduling, test performance, data analysis and generation of final test report. Reference item 36 on Commercial List. 2. All testing associated with “site specific” systems listed in EPC Agreement Exhibit A, Table 1. Activities to include test specification and procedure development, material and equipment procurement, test planning, test scheduling, test performance, data analysis and generation of test report. 3. ASME Pre-service Test Plan development and implementation as noted in the first section above based on the current revision of the ASME-OM document. 4. Steam Generator Moisture Carryover Test procedure development, material and equipment procurement, test planning, test scheduling, test performance, data analysis and generation of test report. Reference item 45 on Commercial List 5. Large Area Testing. Reference item 40 on Commercial List.	Consortium to include all of these items in the ITP at no additional cost to Owner.
42	Procedure revisions from Technical Specification Upgrade (Owner, WEC 50/50)	This issue deals with LAR 13-037 (Technical Specification Upgrade) and the Owner’s position that the technical specifications as written were not usable and would not allow the Owner to successfully operate the plants (reference NND-14-0479). Technical specification examples were given in NND-14-0479 relating to the Steam Generator Isolation Valves flow path, Reactor Coolant Pump minimum flow parameters and the Radioactive Effluent Control Program.	Contractor to provide a proposal to APOG for the requested scope per letter dated October 7, 2015 from APOG with subject: APOG-2015-007 Request for Quote - Technical Specifications Upgrade Impacts. Scope will be performed in accordance with and under the terms of an APOG purchase order. In the event the work is not performed through APOG, Westinghouse to provide technical specifications that are technically accurate and easily understandable and Contractor to complete items #1-5 in VSP_VSG_002989.
43	Providing As-Built Drawings	EPC Table 2-1 makes reference to As-Built and As-Designed separately from each other. Consortium members have verbally communicated that they interpret As-Built to be the As-Designed document combined with the associated change documentation. This is not consistent with SCE&G’s understanding of the term As-Built. WEC procedure APP-GW-GAP-615, Appendix F5 states - To pass release for the core load and turnover to the Owner, the design shall: The design input document shall have no open items or unincorporated changes; Design output documents shall be complete, numeric, and consistently relate to the design input document. A numeric revision, verified compliance document is required and shall demonstrate that the design output documents have met all design input requirements. Design output shall have considered and reconciled the impact from as built and as-tested conditions that may impact core load. NRC Inspection Manual, Inspection Procedure 65001, “Inspections of Inspections, Tests, Analyses and Acceptance Criteria (ITAAC) Related Work”, Attachment 65001.A, requires the following: 02.04 Review As-Built Deviations / Non-Conformances: a. Review a sample of documents that were used to identify differences between the as-designed and as-built SSCs to determine if: i. The difference, if not corrected to comply with the as-designed conditions, was properly documented and incorporated in the final as-built drawings.	To preclude any discussion or confusion regarding what may or may not impact core load, at no additional cost to Owner, WEC to turn over to SCE&G all documents as described in EPC Table 2-1, in an as-built state, with all changes and dimensional discrepancies incorporated into the document. Owner understands the engineering backlog on change paper is growing and immediate actions are required to be able to deliver “clean paper”. Owner understands that additional changes may occur after Turnover and is prepared to address processes to handle these changes.
44	Operating Procedure Configuration Control (Owner to incorporate All post-Baseline 7 Design Changes)	Westinghouse continues to make design changes to the Facility that effect standard operating procedures delivered to the Owner. Identification of the affected procedures is essential to ensure that the operating plant procedures are consistent with the plant design as required.	At no additional cost to Owner, Westinghouse to identify the impact of all design changes on operating procedures and provide this information to Owner.
45	Steam Generator Moisture Carryover Test	Refer to item 41 on Commercial List.	Refer to item 41 on Commercial List.
47	Communication System and BIS Power Allocation	For the Communication System issue, the initial Consortium design did not take into account the site layout of the plants sold to SCE&G. Designs were for a single unit and ended at the security fencing. The Consortium's initial position was that their responsibility for wireless and wired phones, paging system, radios and networking systems ends at the “fence line.” SCE&G contends that the Consortium is responsible to extend these systems to the site specific areas like RWS intake structure, CWS cooling towers, and OWS facility. For the BIS Power Allocation issue, power allocated for Communications is not sufficient for SCE&G needs (e.g. powering phones, cameras, etc.). Per design documents, 48.6kW total power was allocated for both BIS and EFS networks. EFS would be allocated 35kW with the remaining 13.6kW allocated for BIS. SCE&G determined that the BIS power use was 38.4kW versus the 13.6kW allotted in the design.	For the Communication System issue, Consortium letter VSG_VSP_002475 dated October 9, 2013 established an acceptable DOR addressing the majority of the issues and site layout change order 26 resolved the remaining issues. For the BIS Power Allocation issue, Consortium to work with Owner to achieve adequate BIS power to support SCE&G communication needs at no additional cost to Owner.

Confidential Trade Secret Information - Subject to Restricted Procedures                

49	Site Security System Backup Power	AP1000 Design Change Proposal APP-GW-GEE-2710 “Annex Building Security Features Update” identifies the back-up duration for the security system to be less than that identified in APP-GW-GLR-066 “AP1000 Safeguards Threat Assessment” and section 3.6.9 of NUREG-1793, “Final Safety Evaluation Report Related to Certification of the AP1000 Standard Design.” The Owner does not accept this reduction in back-up power reduction as referenced in NND-14-0689.	Westinghouse to provide the required back-up power duration. The Owner is willing to consider the reduced back-up power duration contingent upon WEC’s integration of the Plant Security Systems (SES) for Units 2 and 3 (Reference NND-14-0689).
50	OWS Security Plan	The Offsite Water System (OWS) Treatment Facility includes security and fencing plans that have been discussed with the Consortium and incorporated in the pricing for the latest draft Change Order 17 dated May 10, 2015. Correspondence relating to the OWS Security Plan includes VSP_VSG_001469, NND-11-0444, VSP_VSG_001605 and NND-12-0034. Incremental OWS security plan costs required to meet Owner corporate standards became a commercial issue, specifically the security and fencing requirements and the fire alarm system and fire detection system. Other OWS commercial issues included in the draft CO 17 are the numbering and tagging of equipment and coatings and pipe color requirements. It is noted that the primary OWS change reflected in the draft CO 17 is the addition of the reverse osmosis system to remove bromides from the water. The Owner and Consortium negotiated a “no EPC Agreement price increase” change order for CO 17 which included the OWS security and fencing plans as well as the other items referenced herein. The draft CO 17 also includes other commercial items agreed upon by the Owner and Consortium.	That the Consortium complete the installation of the OWS security, fencing and other items above to the satisfaction of the Owner. CO 17 is addressed in Commercial List item #70.
55	PEB Design Change	The Consortium and SCE&G could not initially come to agreement on the design requirements of the Plant Entry Building.	This issue was resolved with the issue of change order 26.
57	Fire Alarm monitoring	Due to the delay in the project schedule, the Owner is concerned about the increasing value of inventory in the onsite warehouses 20A, 20B and 57 in relation to the insurability of the warehouses and their content under the Owner’s Builder’s Risk Policy. Owner has elected to implement enhancements to the fire alarm monitoring for these warehouses, which includes monitoring of sprinkler system water flow switches in the three warehouses and interconnecting the new system to the existing yard fire alarm system. On October 7, 2015, the Consortium provided to the Owner a draft CO for Owner’s review and comment.	The Consortium to install new local fire alarm control panels in Warehouses 20A and 57; the flow switches will be monitored locally at each of these 2 warehouses. A new main fire alarm panel will be installed in Warehouse 20B. This new main fire alarm panel will monitor the Warehouses 20A and 57. The new main fire alarm panel will be network connected to the existing Siemens fire alarm system using single mode fiber optic connections. Spare fibers which run between the buildings shall be assigned for this purpose. All alarms from the new warehouse fire detection system will be monitored by the existing system’s main fire alarm panel located in the main plant entry guard shack. Physical connection with the existing system’s network shall be made at the YFS fire pump house. The new fire detection system for the three warehouses will be designed as a Class B system; Class A monitoring is not required to satisfy the requirements of the authority having jurisdiction codes for these warehouses.
60	Laurens Piping Quality Issues	CB&I Laurens issued a self-imposed Stop Ship on March 12 following a CB&I Power Audit (V2015-035), which included two Level 1 findings and three Level 2 findings. Most of the issues were repeat Findings from previous Audits/Surveillances performed by CB&I Power. CB&I Laurens issued a Stop Work Order (SWO) on all Safety Related (SR) ASME Section III piping on March 17. The issuance of this SWO was during the March NRC inspection which found many similar issues documented in the CB&I Audit (V2015-035). The major issues being addressed by the SWO are CGD and Qualification of Vendors, Internal and External Audit Programs, Document Control, and Corrective Action Program. During CB&I Power Surveillance 2015-172, which occurred in August 2015, the surveillance team discovered that issues with CGD and Qualification of Vendors had not been fully addressed by CB&I Laurens. This was also noted as an indicator that the corrective actions with the CAP had not been fully effective. July 2015, CB&I Site QC inspection of pipe spools not signed off by Laurens ANI resulted in an approximate reject rate of 65%. These were due to minimum wall violations, dimensional issues, and misfabrications. These results have raised questions on inspection methodologies between Summer, Laurens, Vogtle, and Source Inspection. An additional CBI Laurens self-imposed SWO was put in place on 10/09/15 regarding the incorrect VALVES being place in a pipe spool. The preliminary investigation determined that this does not affect Section III Safety Related pipe spools and has only effected a single spool. However, this investigation is only preliminary and a full Extent of Condition has not been performed. In addition to the Laurens SWO CBI Power has issued QRL restrictions for shipping of Laurens ASME SR spools unless they are released (after enhanced inspection) by the CB&I site QA Directors. Currently Pipe Spools have only been released in phases 1-3 of a 4 phase SWO. No spools will be released to phase 4 until completion of First Article Survey(FAS) by CB&I Power. Once all Spools are completed through Phase 4, the SWO will be lifted.	1. Completion of Corrective Actions associated with stop work /stop ship and lifting of restrictions. 2. Agreement on inspection methodologies between Vogtle, Summer, Laurens, and Source Inspection. 3. Completion of Enhanced Inspections on post SWO pipe spools performed by VC Summer QC. 4. Sustainable Improvements in programmatic systems reported from Audit/Surveillance results performed by CB&I Power.
67	Common Q/Ovation MTS	Owner needs to have an Ovation MTS so Owner can train its technicians and engineers on Ovation equipment in the Ovation Maintenance and Ovation Core Team training areas. The Ovation MTS provides an offline environment with a representative sample of system hardware representing the Distributed Control and Information System (DCIS). In the plant, the Ovation platform is used for the Plant Control System, the Data Display and Processing System, and portions of the Operator Interface of the Operations and Control Centers System (collectively DCIS). Owner provided a revised scope of work to Westinghouse on September 9, 2015 and requested an updated cost proposal. [Note: Common Q MTS CO was in August 2015]	Westinghouse to provide the Ovation MTS, to include the hardware, software, documentation and support, as described in the revised scope of work, which was emailed to Westinghouse on September 9, 2015.
69	Path forward to execute CO16	CO#17 provides clarification information for CO#16. If CO #17 is to be executed, the 2 COs need to be executed together. However, the project schedule upon which CO#16 was based no longer reconciles with the current working schedule.	1. Reach agreement with Consortium on execution of CO #16 and/or CO #17 2. If CO #16 is executed, determine whether schedule language in CO #16 should be modified 3. If schedule language needs to be modified, reach agreement with Consortium on updated language 4. Reach agreement with Consortium on whether Exhibit F schedules should be included in the CO, specific to CO #16. Consortium has proposed not including Exhibit F tables, since the information would be stale at the time of CO execution; instead the impacts of CO #16 to the Exhibit F milestones would be incorporated into an EPC Amendment. 5. Execute alone or simultaneously with CO #17
70	Path forward to execute CO17	CO#17 provides clarification information for CO#16; If CO #17 is to be executed, the 2 COs need to be executed together. However, the project schedule upon which CO#16 was based no longer reconciles with the current working schedule	1. Reach agreement with Consortium on execution of CO #16 and/or CO #17 2. If CO #17 executed, reach agreement with Consortium on whether Exhibit F schedules should be included in the CO, specific to CO #17 (Tables F.1.6 (f-h)). Consortium has proposed not including Exhibit F tables, since the information would be stale at the time of CO execution; instead the impacts of CO #17 to the Exhibit F milestones would be incorporated into an EPC Amendment. 3. Owner to transmit agreed-to de-escalation process since it is not included in CO as Owner requested. 4. If executed, execute simultaneously with CO #16

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77	TEDV DAQ Funding	Purchase agreement between Westinghouse, Southern and SCE&G is to provide the data acquisition system and capability to support thermal expansion and dynamic evaluation of plant components during testing.	Westinghouse to deliver TEDV DAQ in accordance with purchase agreement.
96	Offsite Storage and Lay down – Leases, Equipment, and FNM Per Diem (area 14, Blythewood, Metro)	During Phase I of the EPC Agreement scope of work, the Owner paid the Contractor to develop the requirements for all temporary facilities on the Site, to include warehouses and equipment and material laydown areas. The Contractor developed the requirements, was given unlimited access to the Site and was in control of the Target Price budget for construction of the appropriate facilities. The Contractor now estimates significantly more warehouse facilities and laydown area space than it originally planned. The Owner contends that this additional warehouse and laydown area space is attributed to either inadequate planning on the part of the Contractor or structural module delay. The facilities and laydown area in question at this point are the Blythewood warehouse facility, Metro warehouse facility and laydown area 18. The Blythewood warehouse is being utilized and the lease payments invoiced to the Owner have been disputed. The Metro facility renovation is essentially complete and ready to receive equipment and material. The Contractor will begin invoicing the Owner for the lease and other expenses. The Area 14 laydown area construction has been out for bids by the Contractor who has been having discussions with the Owner on the invoicing process. The Contractor claims entitlement to a change order for these warehouse facilities and laydown area expenses since they are located off-site. The Owner disagrees and is willing to treat these facilities as target scope work under the EPC Agreement with no justification for a change order. Also, the Owner’s position is that CO 8 applies which transferred target dollars to fixed/firm dollars for items such as construction equipment and field non-manual living expenses.	The Contractor invoice the Owner for the Blythewood and Metro warehouses and Area 15 laydown area construction under the Target Price category per the EPC Agreement, applying the CO 8 cost categories to the invoicing. The total costs for these facilities and laydown area will remain in dispute per the EPC Agreement due to the structural module delay with resolution dependent upon senior executive negotiations.
97	Warranty impact due to delay and specific warranty claims; and extending warranties based on actual completion dates	The warranty requirements are specified in Article 14 of the EPC Agreement. Specifically, a 24 month warranty period for Equipment begins upon the actual Substantial Completion Dates for Units 2 and 3. The presently approved Guaranteed Substantial Completion Dates for Units 2 and 3 are March 15, 2017 and May 15, 2018, respectively. The Owner’s position is that the 24 month warranty period and other warranty provisions in the EPC Agreement should be effective upon the actual Substantial Completion dates due to the structural module delay impact on the Project Schedule. Also, there are specific warranty claims that the Consortium is responsible for resolving. For example, the Units 2 and 3 Switchyard has experienced component failures, specifically related to capacitors, as noted in Owner correspondence NND-14-0335, NND-14-0337, NND-14-0514 and NND-14-0627. Other components also sustained damages, but were replaced by the Consortium with extended warranties (reference VSP_VSG_002978). The Consortium has been working with the Owner and capacitor manufacturer (ABB/Maxwell) to perform analyses and testing to determine root cause. In the meantime, capacitors have been removed from the Switchyard, which is presently operating at partial capacity due to these capacitor issues.	1. Consortium extends 24 month warranty provision and other warranty provisions of Article 14 of the EPC Agreement to be effective upon the actual Substantial Completion Dates for Units 2 and 3. 2. Consortium resolves all outstanding warranty claims, to include the Switchyard capacitor failure claim, to the Owner’s satisfaction. This will include component extended warranties as applicable.
98	Cyber-Security	The Owner’s position is that the Consortium is committed in the EPC Agreement to provide a cyber security program for VCS Units 2 and 3 that complies with APP-GW- GLR-104, “AP1000 Cyber Security Implementation,” dated May 2007 (also referred to as TR-104). TR-104 is a requirement included in the AP1000 Design Control Document (DCD) Revision 16 which is referenced in the EPC Agreement. The Owner acknowledges that the NRC issued Regulatory Guide (RG) 5.71, “Cyber Security programs for Nuclear Facilities,” subsequent to the execution of the EPC Agreement and that there is a level of incremental scope of work which has not been satisfactorily resolved to the satisfaction of the Owner. The Owner and Consortium agreed to a Phase I Cyber Security CO (#14), which was executed on March 14, 2012 The Owner and Consortium have attempted to negotiate a Phase 2 Cyber Security CO but have been unsuccessful to date. A significant impasse dealt with the Consortium’s refusal to accept project schedule risk and mandate to Owner a release of the Guaranteed Substantial Completion date for Unit 2. A Phase 2 Cyber Security technical scope of work has been agreed upon and is included in the latest draft Cyber Security CO dated February 19, 2015 (VSP_VSG_003270). This technical scope is entitled “Technical Description for Consortium for AP1000 Consortium Cyber Security Scope of Supply.” The Owner and Consortium have discussed scopes of work beyond Phase 2, although no Technical Description for Phase 3 has been defined. For example, in a previous draft Cyber Security CO dated February 28, 2013, Phase 3 scope topics were addressed to include potential warehouse modifications to handle storage and handling of Critical Digital Assets (CDA’s), the training of site personnel to deal with CDA’s and site installation and Field Change Notices associated with hardware and software modification. The Owner and Consortium have also had discussions that Phase 3 work would involve dealing with suppliers of equipment for potential smart equipment upgrades. The Owner is concerned that the negotiations on cyber security have been unnecessarily delayed as evidenced by timelines maintained by the Owner and the Consortium’s decision to hold up work on cyber security and demobilize personnel earlier this year. It is noted that the Owner had authorized dollars for the Consortium to perform cyber security work during the negotiations and had requested that the Consortium continue with the interim funding provided by the Owner.	Subject to Paragraph 4 of the October 2105 Amendment, Consortium to provide a cyber security program in accordance with RG 5.71 and accept schedule risk to meet Guaranteed Substantial Completion Dates agreed to between Owner and Consortium. All phases of the Cyber Security Program are included in this scope, which also includes the Phase 2 technical scope referenced in the draft CO dated February 19, 2015.

Disputed and Returned Payments

Exhibit B

As of August 21, 2015

WEC Claim
	Regulatory Delay Claim	$	83,518,046
Payment Entitlement in Dispute
	Capped Esc due to Structural Module Delay	$	6,275,414
	Cyber Security	$	374,613
	Target Invoice Returns (storage, tents, firm price)	$	13,289,433
	Target Invoice Withholding (10%) Due to Delay and
	Performance Inefficiencies	$	7,657,127
	Interest Expense on Returned Invoices	$	2,133,198
	Total	$	29,729,785
No Dispute, Payments Pending CO Execution		$	5,565,845
	HW Escalation Calculation	$	5,565,845
	Total
Timing of Payment in Dispute
	Progress Payments	$	99,066,205
	Milestones Not Complete	$	11,124,299
	Total	$	110,190,504

EXHIBIT C

Items Not Resolved or Released under October 2015 Amendment

Description	Reference
Data Turnover and documentation required
Containment Debris Margin Increase	NND-11-0166; VSP_VSG_001218
Auxiliary Boiler design capability
Electromagnetic Capability (EMC) with Protection & Safety Monitoring System (PMS) -
American Society of Mechanical Engineers(ASME) Boiler and Pressure Vessel Code Section VIII pressure vessel over pressure protection	NND-15-0460; VSP_VSG_003682
Site Layout changes, Phase 3, due to security regulatory changes
Onsite automation/I&C Support to Owner during post initial core load
Onsite switchyard preoperational test
Plant Security System (SES) testing
Plant Security System (SES) Unit 2&3 Computer Integration

Confidential Trade Secret Information - Subject to Restricted Procedures                

AGREEMENT

AMENDMENT TO THE ENGINEERING, PROCUREMENT AND CONSTRUCTION AGREEMENT BETWEEN SOUTH CAROLINA ELECTRIC & GAS COMPANY, FOR ITSELF AND AS AGENT FOR THE SOUTH CAROLINA PUBLIC SERVICE AUTHORITY AND A CONSORTIUM CONSISTING OF WESTINGHOUSE ELECTRIC COMPANY LLC AND STONE & WEBSTER, INC., FOR AP1000® NUCLEAR POWER PLANTS

THIS AMENDMENT to the Engineering, Procurement and Construction Agreement dated May 23, 2008 (“EPC Agreement”) for the AP1000 Power Plants at the Virgil C. Summer Nuclear Generating Station (“Project”) by and between South Carolina Electric & Gas Company, for itself and as agent for the South Carolina Public Service Authority (“Owner”) and a consortium consisting of Westinghouse Electric Company LLC (“Westinghouse”) and CB&I Stone & Webster, Inc. (“S&W”), (collectively “Contractor”) is executed on behalf of Westinghouse, shall be executed on behalf S&W upon the consummation of the Transaction (as defined in the October 2015 Amendment) and shall become effective upon execution by Owner and approval of the Public Service Commission of South Carolina, so long as execution occurs by the 1^st day of November 2016, unless such approval is waived by the Owner or the date is waived by the Contractor (“Option Amendment”). If execution does not occur by November 1, 2016, this Option Amendment shall be null and void in all respects. Owner and Contractor may be referred to individually as a “Party” or collectively as the “Parties.”

In consideration of the mutual promises herein and other good and valuable consideration, the receipt and sufficiency of which the Parties acknowledge, the Parties, intending to be legally bound, stipulate and agree as follows:

1.Except as provided in paragraph 2, all remaining Work under the EPC Agreement as of the Effective Time (defined in the October 2015 Amendment referenced below) shall be converted to a Fixed Price in exchange for the remaining Contract Price being adjusted to $6.082 billion in current U.S. Dollars. The remaining Contract Price adjustment represents the cost to complete the Project beyond what has been paid through June 30, 2015. Payments made after June 30, 2015 will be credited against the $6.082 billion amount.

2.The following Time and Material Work is not included in the Fixed Price described in paragraph 1: sales tax, performance bond and insurance premiums, import duties, Mandatory Spare Parts and Extended Equipment Warranty costs (other than the costs associated with the warranty extensions provided for in paragraph 7 of the October 2015 Amendment, because those warranty extensions are at no cost to Owner). This Work will be billed under the existing terms of the EPC Agreement.

3.The categories of Target Price and Firm Price are eliminated.

4.The capitalized terms in this Amendment, except for those defined in this Amendment, shall have the meanings given to them in the EPC Agreement.

5.All provisions of the EPC Agreement not modified, expressly or by necessary implication, remain in full force and effect.

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Confidential Trade Secret Information - Subject to Restricted Procedures                

IN WITNESS WHEREOF, the Parties have duly executed this Amendment as of the date first above written.

SOUTH CAROLINA ELECTRIC & GAS

COMPANY, for itself and as agent for South

Carolina Public Service Authority

By:

Name:

Title:

WESTINGHOUSE ELECTRIC COMPANY LLC
By:	/s/Danny Roderick
Name:	Danny Roderick
Title:	President & Chief Executive Officer

STONE & WEBSTER, INC.

By:

Name:

Title:

2

Dispute Review Board Agreement

THIS DISPUTE REVIEW BOARD AGREEMENT (“DRB Agreement”) concerning the Engineering, Procurement and Construction Agreement dated May 23, 2008 (“EPC Agreement”) for the AP1000 Power Plants at the Virgil C Summer Nuclear Generating Station (“Project”) is effective the ___ day of ______________ 2015, by and between South Carolina Electric & Gas Company, for itself and as agent for the South Carolina Public Service Authority (“Owner”) and a consortium consisting of Westinghouse Electric Company LLC and Stone & Webster, Inc., (collectively “Contractor”). Owner and Contractor may be referred to individually as a “Party” and collectively as the “Parties.”

WHEREAS, the Parties wish to establish a Dispute Resolution Board (“DRB”) for addressing all Claims, as defined in the EPC Agreement, and other disputes that may arise out of or relate to the Project and provisionally resolving such claims.

NOW, THEREFORE, in consideration of the recital, the mutual promises herein and other good and valuable consideration, the receipt and sufficiency of which the Parties acknowledge, the Parties, intending to be legally bound, stipulate and agree as follows:

1.Owner and Contractor agree to the establishment of a DRB in accordance with this DRB Agreement to assist in timely, impartial resolution of Claims and other disputes. All Claims and other disputes arising out of or relating to the EPC Agreement shall be governed by this DRB Agreement, until Substantial Completion of both Units.

2.For Claims and other disputes under $5 million, determinations of the DRB shall be binding on the Parties.

3.For Claims and other disputes of $5 million or higher, determinations of the DRB shall be treated as binding on the Parties on an interim basis until Substantial Completion of both Units. Upon Substantial Completion of both Units, either Party may proceed de novo with dispute resolution in accordance with Article 27 of the EPC Agreement. Determinations of the DRB will not be admissible in any de novo proceedings pursuant to Article 27 of the EPC Agreement.

4.For Claims and other disputes of $5 million or higher, Owner and Contractor shall submit their written acceptance or rejection of the DRB’s report concurrently to the other Party and to the DRB within fourteen (14) days of receipt of the report. Failure by either Party to accept or reject within the specified period shall be deemed acceptance of the report by that Party. If both Parties accept the report, then it shall be final, without qualification. If one or both Parties reject the report, they shall nonetheless treat the report as binding until thirty (30) days after Substantial Completion of both Units, at which point the report will have no force or effect.

5.The process outlined in this DRB Agreement shall be the exclusive dispute resolution process for all Claims and other disputes under the EPC Agreement and shall be in lieu of the process set forth in Articles 27.3 and 27.4 of the EPC Agreement, until Substantial Completion of both Units. Thereafter, for Claims or other disputes covered by Paragraph 3 of this DRB Agreement, the Parties may proceed as stated in Paragraph 3.

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6.Within thirty (30) days of the execution of the November 2015 Amendment, each Party shall submit to the other Party for approval the names of its nominees for membership on the DRB. The Parties shall mutually agree on the three members of the DRB. Once constituted, the DRB members shall designate one of them as Chair of the DRB. The DRB shall serve until Substantial Completion of both Units.

7.Members of the DRB shall be experienced in the interpretation of contract documents, the resolution of construction disputes, and with complex power plant projects. At least one of the DRB members must be a licensed attorney. To assist the Parties in the review and approval process, nominated members shall provide the following, in addition to the nominee’s full name and contact information, to both Parties:

A. Resume showing construction experience qualifying the person as a DRB member.

B. Resume showing past DRB participation, if any. This resume will each DRB assignment separately, and state the name and location of the project, dates of DRB service, name of owner, name of contractor, contract value, nominating party if applicable, names of the other DRB members, and the number of disputes heard.

C. All three members of the DRB are to be neutral and must affirm their neutrality, under oath, once the DRB is fully constituted and before the DRB takes any action.

D. Disclosure statement describing past, present, and anticipated relationships or financial ties, including indirect relationships through the nominee’s full-time employer, if any, to the Project, and with the Parties and with all other entities directly and indirectly involved in the EPC Contract. Entities indirectly involved include Fluor, designers, architects, engineers, or other professional service firms or consultants, joint-venture partners, subcontractors of any tier, and suppliers on the Project. The disclosure statement will also disclose close professional or personal relationships with key members of the Parties and these entities.

E. Neutrality and disclosure is a continuing obligation of all DRB members throughout the life of the EPC Contract.

F. Each member of the DRB shall execute non-disclosure agreements as required by the Parties.

G. No DRB member shall be allowed to act as an arbitrator or appear as a witness in any subsequent arbitration or litigation related to or arising out of the EPC Agreement.

8.Once fully constituted, the DRB will visit the project site and meet with representatives of the Parties at periodic intervals and as requested by the Parties. Any discussion and field observation shall be attended by personnel of the Owner and Contractor.

9.Owner and Contractor shall enter into good-faith negotiations to settle a dispute before referring such dispute to the DRB. These good-faith negotiations shall be involve full and timely disclosure of each Party’s position to the other Party, including the exchange, where applicable, of pertinent supporting records, analyses, expert reports, and similar documentation, and shall proceed without delay following the inception of the dispute. Such good-faith negotiations may involve the solicitation and rendering of a DRB advisory opinion as described herein.

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10.Either Owner or Contractor may refer a dispute to the DRB. The dispute referral shall be made in writing to the DRB Chair with a copy concurrently provided to the other DRB members and the other Party.

11.The dispute referral shall concisely define the nature and specifics of the dispute that are to be considered by the DRB and the scope of the determination requested. The DRB Chair shall confer with the Parties to establish a due date for delivering pre-hearing submittals, and a date, time, and location for convening the DRB hearing. Hearings shall be convened, at a location mutually agreed by the Parties. Absent such agreement by the Parties, the DRB shall determine the location of the hearings.

12.The procedures governing the hearings shall be established by agreement of the Parties. Absent such agreement, the DRB shall establish such hearing procedures.

13.The DRB’s determination of a dispute will be formalized in a written report with format as determined by the DRB and signed by all DRB members. The report shall consist of a concise description of the dispute, short statements of each Party’s position, findings as to the facts of the dispute, discussion and rationale for the determination, and the determination. The report shall be submitted concurrently to the Parties, no later than thirty (30) days after completion of the hearing as agreed by all Parties.

14.Owner and Contractor shall each bear their respective costs and attorney’s fees. Owner and Contractor shall equally bear the cost of the DRB’s services.

IN WITNESS WHEREOF, the Parties have duly executed this DRB Agreement as of the date first above written.

SOUTH CAROLINA ELECTRIC & GAS

COMPANY, for itself and as agent for South

Carolina Public Service Authority

By:

Name:

Title:

WESTINGHOUSE ELECTRIC COMPANY LLC

By:

Name:

Title:

STONE & WEBSTER, INC.

By:

Name:

Title:

3

EXHIBIT F

CONSENT OF GUARANTOR

This Consent is made by TOSHIBA CORPORATION (“Guarantor”), a corporation duly organized and existing under the laws of Japan and the indirect parent of Westinghouse Electric Company LLC (“Westinghouse”).

WHEREAS, Westinghouse and Stone & Webster, Inc. (“Stone & Webster”, and collectively with Westinghouse, the “Contractor”) and South Carolina Electric & Gas Company, for itself and as agent for the South Carolina Public Service Authority (collectively, the “Counterparty”) are parties to the Engineering, Procurement and Construction Agreement between the Contractor and the Counterparty, dated as of May 23, 2008 (the “Agreement”); and

WHEREAS, in connection with the Agreement, Guarantor executed and delivered to Counterparty a guaranty of the payment obligations of Westinghouse under the terms of the Agreement (the “Guaranty”); and

WHEREAS, the Agreement is being amended by an Amendment dated October 27, 2015 (the “October 2015 Amendment”); and

WHEREAS, Guarantor, as indirect parent of Westinghouse, shall receive benefit from the transaction contemplated by the Agreement as previously amended and as amended by the October 2015 Amendment and has agreed to give this Consent to provide assurance for Westinghouse’s payment obligations in connection with the Agreement as so amended; and

WHEREAS, Guarantor acknowledges the execution and delivery of this Consent is required by the terms of the October 2015 Amendment.

NOW, THEREFORE, in consideration of the premises and other good and valuable consideration, the adequacy, receipt and sufficiency of which are hereby acknowledged, Guarantor hereby agrees as follows:

1.Guarantor acknowledges the terms of the October 2015 Amendment.

2.The definition of Guaranteed Obligations in the Guaranty includes all payment obligations of Westinghouse under the terms of the Agreement, as previously amended and as amended by the October 2015 Amendment.

3.Guarantor hereby reaffirms the Guaranty and agrees that, except as provided herein, the Guaranty shall remain unchanged and in full force and effect. Each and every term, covenant and condition of the Guaranty is hereby incorporated herein such that the Guaranty and this Consent shall be read and construed as one instrument.

4.The validity, construction, and performance of this Consent of Guarantor shall be governed by and interpreted in accordance with the laws of the State of New York, without

giving effect to the principles thereof relating to conflicts of laws except Section 5-1401 of the New York General Obligations Law.

IN WITNESS WHEREOF, Guarantor has caused this Consent to be executed in its corporate name by its duly authorized representative.

TOSHIBA CORPORATION

By: /s/Shigenori Shiga                      

Name: Shigenori Shiga    

Title: Representative Executive Officer    

Date: October 27, 2015    

Acknowledged and Agreed by Counterparty as of this 27 day of October, 2015, by:

/s/Kevin B. Marsh                 

Name: Kevin B. Marsh    

Title: CEO, SCANA Corp    

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MUTUAL RELEASE

This Mutual Release (“Mutual Release”) is executed this 27th day of October, 2015, by South Carolina Electric & Gas Company, a South Carolina corporation having a place of business in Cayce, South Carolina, South Carolina Public Service Authority, a body corporate and politic created by the laws of the State of South Carolina (collectively, “Owners”) and Chicago Bridge & Iron Company N.V. (“CB&I”), a corporation organized under the laws of the Netherlands.

RECITALS

WHEREAS, Owners and a consortium consisting of Westinghouse Electric Company LLC (“Westinghouse”) and CB&I Stone & Webster, Inc. (“S&W”) (collectively, the “Contractor”) entered into an Engineering, Procurement and Construction Agreement with an effective date of May 23, 2008 (as amended or supplemented, the “EPC Agreement”) pursuant to which the Contractor agreed to assist Owners in the licensing of and to design, engineer, procure, construct and test two AP1000 Nuclear Power Plants and related facilities, structures and improvements known as Units 2 and 3 located at the V.C. Summer station in Jenkinsville, South Carolina, and owned by Owners (the “Project”);

WHEREAS, pursuant to the EPC Agreement, S&W furnished to Owners a Corporate Guarantee dated and effective as of May 23, 2008 and issued and executed by S&W’s then-ultimate holding corporation, The Shaw Group, Inc. (“Shaw Group”) (as amended or supplemented, the “S&W Parent Guarantee”);

WHEREAS, thereafter, in connection with the acquisition by CB&I of Shaw Group, CB&I executed and furnished to Owners a Corporate Guarantee dated April 29, 2013 (the “CB&I Guarantee”), which replaced the S&W Parent Guarantee;

WHEREAS, Contractor has submitted various notices of Change and Change Dispute Notices pursuant to the EPC Agreement that remain unresolved and various commercial issues, Change Disputes and Claims (as defined in the EPC Agreement) are pending under the EPC Agreement (collectively, “EPC Claims”);

WHEREAS, simultaneously with the execution and delivery of this Mutual Release, Owners and Westinghouse are entering into a binding Settlement and Release Agreement (the “Settlement Agreement”), with respect to, among other things, the EPC Claims;

WHEREAS, Westinghouse, S&W, an affiliate of Westinghouse (“Purchaser”), and CB&I are entering into a Purchase Agreement pursuant to which, among other things, Purchaser will purchase all of the outstanding capital stock of S&W; and

WHEREAS, effective upon the Effective Time (as defined in Paragraph 3), Owners and CB&I agree to release one another from any and all past, current and future duties, obligations, claims and liabilities arising out of or related to the EPC Claims, the EPC Agreement, the Project, the S&W Parent Guarantee and the CB&I Guarantee.

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NOW, THEREFORE, in consideration of the recitals and the mutual promises, covenants and agreements contained in the Settlement Agreement and herein, and for other good and valuable consideration, the receipt, adequacy and sufficiency of which are hereby acknowledged, Owners and CB&I mutually, release one another as follows.

RELEASE

1.    Effective upon the Effective Time, Owners, for themselves and their respective officers, agents, directors, partners, managing members, stockholders, owners, employees, attorneys, advisors, representatives, insurers, sureties, predecessors, successors, assigns, parents, subsidiaries and affiliated entities, heirs, executors and administrators (collectively, the “Owner Releasing Parties”) and each of them, hereby unconditionally and irrevocably fully release, forever discharge and covenant not to sue, except for the Excepted Party as defined in Paragraph 2 hereof, CB&I and its past, present, and future officers, agents, directors, partners, managing members, stockholders, owners, employees, attorneys, advisors, representatives, insurers, sureties, predecessors, successors, assigns, parents, subsidiaries, and affiliated entities, heirs, executors and administrators (collectively, the “CB&I Released Parties”), and each of them, from any and all manner of actions, controversies, suits, matters, liens, rights, liabilities, losses, debts, dues, damages, claims, guarantees, warranties, judgments, bonds, executions, obligations, accounts, fines, regulatory penalties (whether civil or criminal), costs and expenses (including attorneys’ fees) and demands (collectively, “Claims/Obligations”) of every nature, kind and description whatsoever in law or in equity, whether known or unknown, or whether suspected or unsuspected, or whether matured or un-matured, whether liquidated or unliquidated, under any theory, including joint and several liability, which Owners had, now have, or hereafter can, shall or may have against CB&I or any of the other CB&I Released Parties arising out of any manner or event relating to, or otherwise in connection with or concerning, the EPC Claims, the EPC Agreement, the Project, the S&W Parent Guarantee and the CB&I Guarantee.

2.        This Mutual Release is not in favor, and does not inure to the benefit, of S&W (being referred to herein as the “Excepted Party”) and it being understood and acknowledged that any release in favor of S&W is solely as set forth in the Settlement Agreement. Except for the Excepted Party as defined in Paragraph 1 hereof, effective upon the Effective Time, CB&I, for itself and its respective officers, agents, directors, partners, managing members, stockholders, owners, employees, attorneys, advisors, representatives, insurers, sureties, predecessors, successors, assigns, parents, subsidiaries and affiliated entities (but only to the extent any such subsidiary or affiliated entity is a subsidiary or affiliated entity after the Effective Time), heirs, executors and administrators (collectively, the “CB&I Releasing Parties”) and each of them, hereby unconditionally and irrevocably fully release, forever discharge and covenant not to sue, Owners and their past, present, and future officers, agents, directors, partners, managing members, stockholders, owners, employees, attorneys, advisors, representatives, insurers, sureties, predecessors, successors, assigns, parents, subsidiaries, and affiliated entities, heirs, executors and administrators (collectively, the “Owners Released Parties”), and each of them, from any and all manner of actions, controversies, suits, matters, liens, rights, liabilities, losses, debts, dues, damages, claims, guarantees, warranties, judgments, bonds, executions, obligations, accounts, fines, regulatory penalties (whether civil or criminal), costs and expenses (including

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attorneys’ fees) and demands (collectively, “Claims/Obligations”) of every nature, kind and description whatsoever in law or in equity, whether known or unknown, or whether suspected or unsuspected, or whether matured or un-matured, whether liquidated or unliquidated, under any theory, including joint and several liability, which CB&I had, now have, or hereafter can, shall or may have against Owners or any of the other Owners Released Parties arising out of any manner or event relating to, or otherwise in connection with or concerning, the EPC Claims, the EPC Agreement, the Project, the S&W Parent Guarantee and the CB&I Guarantee.

3.    This Mutual Release does not release any rights of S&W, the Excepted Party, it being understood and acknowledged that any release by S&W is solely as set forth in the Settlement Agreement.

4.        Westinghouse and Owners have agreed that the Settlement Agreement will automatically become effective upon the closing of the purchase by Westinghouse or an affiliate of Westinghouse of all of the outstanding capital stock of S&W (such time of closing, the “Effective Time”).

5.    This Mutual Release and the application and interpretation thereof shall be governed exclusively by the laws of the State of New York without regard to conflicts of laws principles.

6.    This Mutual Release shall be fully binding upon each Owner, CB&I and their respective legal representatives, successors and assigns.

7.    The releases contemplated by Section 1 and 2 are intended to be as broad as permitted by law, provided that nothing in Section 1 or 2 shall apply to any action by any releasee to enforce the rights and obligations imposed by this Mutual Release. Without limiting the foregoing, for the avoidance of doubt, the releases contemplated by Section 1 and 2 are intended to, and do, extinguish suspected, unmatured, unliquidated and unknown Claims/Obligations even if, confirmation, maturation or knowledge of those Claims/Obligations on the date hereof would have affected the decision to enter into this Mutual Release. The release of suspected, unmatured, unliquidated or unknown Claims/Obligations was separately bargained for and was a key element of this Mutual Release, relied upon by each party in entering this Mutual Release. The Owner Releasing Parties and the CB&I Releasing Parties shall be deemed to have, and by execution of this Mutual Release shall have, expressly waived and relinquished, to the fullest extent permitted by law, any rights or benefits they may have under state law, federal law, foreign law or common law that may have the effect of limiting the release set forth in Section 1, including any rights or benefits conferred by Section 1542 of the California Civil Code or any provision similar, comparable or equivalent to Section 1542 or successor provision to Section 1542 of the California Civil Code, which provides that: A GENERAL RELEASE DOES NOT EXTEND TO CLAIMS WHICH THE CREDITOR DOES NOT KNOW OR SUSPECT TO EXIST IN HIS FAVOR AT THE TIME OF EXECUTING THE RELEASE, WHICH IF KNOWN BY HIM MUST HAVE MATERIALLY AFFECTED HIS SETTLEMENT WITH THE DEBTOR.

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8.        Each of the persons executing this Mutual Release on behalf of its respective principals warrants that he or she is legally entitled to enter into this Mutual Release and release the CB&I Released Parties and the Owner Released Parties from every claim and liability, whether potential or actual, herein referred to, and that he or she has the authority to bind his or her respective principals and has full authority to enter into this Mutual Release.

9.    Owners and CB&I acknowledge and represent that they have each relied solely upon facts obtained from their own independent investigations in executing this Mutual Release and that they each have not relied upon any statements or representations of any nature from the parties to the Settlement Agreement or any other individuals or entities, or such other parties’, individuals’ or entities’ attorneys or representatives. Each Owner and CB&I represent that they have had sufficient opportunity to consult their own legal counsel with regard to the negotiation and preparation, as well as the scope and effect, of this Mutual Release.

10.    Owners and CB&I agree to execute any further documents necessary and take such other actions as to effectuate this Mutual Release.

11.        This Mutual Release may be executed in counterparts, each of which shall be deemed an original and all of which together shall constitute one and the same instrument.

IN WITNESS WHEREOF, Owners and CB&I execute this Release by their duly authorized representatives.

South Carolina Electric & Gas Company

for itself and as agent for the South Carolina Public Service Authority

By /s/Kevin B. Marsh         

Title Chairman & CEO                

Date October 27, 2015                 

Chicago Bridge & Iron Company N.V.

By /s/Richard E. Chandler, Jr.

Title EVP, Chief Legal Officer & Secretary

DateOctober 27, 2015    

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MUTUAL RELEASE

This Mutual Release is entered into this 27th day of October, 2015, and becomes effective as described herein, by and among Westinghouse Electric Company LLC, a Delaware limited liability company having a place of business in Cranberry, Pennsylvania (“Westinghouse”), CB&I Stone & Webster, Inc., a Louisiana corporation with a place of business in Charlotte, North Carolina (“S&W”), and South Carolina Electric & Gas Company (“SCE&G”), for itself and as agent for the South Carolina Public Service Authority, a body corporate and politic created by the laws of South Carolina (“Santee Cooper”) (collectively “Owners”). Westinghouse, S&W and Owners may be referred to individually as “Party” or collectively as “Parties.”

RECITALS

WHEREAS, Owners and a consortium consisting of Westinghouse and S&W (collectively “Contractor”) entered into an Engineering, Procurement and Construction Agreement on May 23, 2008 (“EPC Agreement”) pursuant to which Contractor agreed to design and construct two new nuclear electrical generating units known as V.C. Summer Units 2 and 3 (the “Units”) located at the V.C. Summer Nuclear Generating Station in Jenkinsville, South Carolina (the “Project”);

WHEREAS, Contractor has submitted various notices of Change and Change Dispute Notices pursuant to the EPC Agreement that remain unresolved and various commercial issues, Change Disputes and Claims (as defined in the EPC Agreement) are pending under the EPC Agreement (collectively, “EPC Claims”);

WHEREAS, Owners and Westinghouse are entering into a binding Amendment Agreement (“October 2015 Amendment”) with respect to, among other things, the EPC Claims;

WHEREAS, a Westinghouse affiliate, Chicago Bridge & Iron Company N.V. (“CB&I”), and S&W are entering into a Stock Purchase Agreement pursuant to which, among other things, Westinghouse or an affiliate of Westinghouse will purchase all of the outstanding capital stock of S&W (the “SPA”);

WHEREAS, upon the execution the SPA, Westinghouse shall execute this Mutual Release on its own behalf, and upon the consummation of the SPA (the “Effective Time”) shall cause S&W to execute this Mutual Release on behalf of S&W; and

WHEREAS, upon execution of this Mutual Release by Westinghouse and S&W, this Mutual Release shall become effective as of the Effective Time, and in the event the SPA is not consummated, this Mutual Release shall not become effective and shall be null and void in all respects.

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NOW, THEREFORE, in consideration of the recitals and the mutual promises, covenants and agreements contained in the October 2015 Amendment and herein, and for other good and valuable consideration, the receipt, adequacy and sufficiency of which are hereby acknowledged, Owners, Westinghouse and S&W hereby provide mutual releases as follows.

RELEASE

1.     Except as otherwise provided in the October 2015 Amendment (including Exhibit C to the October 2015 Amendment), upon the Effective Time, Owners, for themselves and their respective officers, agents, directors, partners, managing members, stockholders, owners, employees, attorneys, advisors, representatives, insurers, sureties, predecessors, successors, assigns, parents, subsidiaries and affiliated corporations, heirs, executors and administrators and each of them, hereby unconditionally and irrevocably fully release, forever discharge and covenant not to sue Westinghouse, S&W and their past, present, and future officers, agents, directors, partners, managing members, stockholders, owners, employees, attorneys, advisors, representatives, insurers, sureties, predecessors, successors, assigns, parents, subsidiaries, and affiliated corporations, and each of them, from any and all manner of actions, controversies, suits, liens, losses, debts, dues, damages, claims, attorney fees, guarantees, warranties, judgments, bonds, executions and demands of every nature, kind and description whatsoever in law or in equity, whether known or unknown, or whether suspected or unsuspected, or whether matured or unmatured, whether liquidated or unliquidated, under any theory, including joint and several liability, which Owners had, now have, or hereafter can, shall or may have against Westinghouse and/or S&W for any events or circumstances occurring as of the Effective Time and arising out of any manner or event relating to, or otherwise in connection with or concerning, the EPC Claims, the EPC Agreement and the Project.

2.Except as otherwise provided in the October 2015 Amendment (including Exhibit C to the October 2015 Amendment), upon the Effective Time, Westinghouse and S&W, for themselves and their respective officers, agents, directors, partners, managing members, stockholders, owners, employees, attorneys, advisors, representatives, insurers, sureties, predecessors, successors, assigns, parents, subsidiaries and affiliated corporations, heirs, executors and administrators and each of them, hereby unconditionally and irrevocably fully release, forever discharge and covenant not to sue Owners and their past, present, and future officers, agents, directors, partners, managing members, stockholders, owners, employees, attorneys, advisors, representatives, insurers, sureties, predecessors, successors, assigns, parents, subsidiaries, and affiliated corporations, and each of them, from any and all manner of actions, controversies, suits, liens, losses, debts, dues, damages, claims, attorney fees, guarantees, warranties, judgments, bonds, executions and demands of every nature, kind and description whatsoever in law or in equity, whether known or unknown, or whether suspected or unsuspected, or whether matured or unmatured, whether liquidated or unliquidated, under any theory, including joint and several liability, which Westinghouse and/or S&W had, now have, or hereafter can, shall or may have against Owners for any events or circumstances occurring as of the Effective Time and arising out of any manner or event relating to, or otherwise in connection with or concerning, the EPC Claims, the EPC Agreement and the Project.

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3.This Mutual Release and the application and interpretation thereof shall be governed exclusively by the laws of the State of New York without regard to conflicts of laws principles.

4.This Mutual Release shall be fully binding upon Owners, Westinghouse and S&W and their respective legal representatives, successors and assigns.

5.Each of the persons executing this Mutual Release on behalf of their respective principals warrants that he or she is legally entitled to enter into this Mutual Release and release every claim and liability, whether potential or actual, herein referred to, and that he or she has the authority to bind his or her respective principals and has full authority to enter into this Mutual Release.

6.Owners, Westinghouse and S&W acknowledge and represent that each has had sufficient opportunity to consult its own legal counsel with regard to the negotiation and preparation, as well as the scope and effect, of this Mutual Release.

7.Owners, Westinghouse and S&W agree to execute any further documents necessary and take such other actions as to effectuate this Mutual Release.

8.This Mutual Release may be executed in counterparts, each of which shall be deemed an original and all of which together shall constitute one and the same instrument.

IN WITNESS WHEREOF, the Parties execute this Mutual Release by their duly authorized representatives.

Westinghouse Electric Company LLC		CB&I Stone & Webster, Inc.
By	/s/Danny Roderick	By
Title	President & Chief Executive Officer	Title
Date	October 27, 2015	Date

South Carolina Electric & Gas Company        

for itself and as agent for the South

Carolina Public Service Authority

By	/s/Kevin B. Marsh
Title	Chairman & CEO
Date	October 27, 2015

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EX-12.01

Exhibit 12.01

COMPUTATION OF RATIOS

September 30, 2015

RATIO OF EARNINGS TO FIXED CHARGES

SCANA:	Nine Months Ended September 30, 2015		Twelve Months Ended September 30, 2015		Years ended December 31,
Dollars in Millions					2014			2013			2012			2011			2010
Fixed Charges as defined:
Interest on debt		$243.9		$324.5		$318.2			$305.9			$301.3			$287.0			$270.4
Amortization of debt premium, discount and expense (net)	3.6		7.4		9.7			5.3			4.9			4.8			5.1
Interest component on rentals	2.8		3.9		4.1			4.9			4.9			5.2			4.6
Total Fixed Charges (A)		$250.3		$335.8		$332.0			$316.1			$311.1			$297.0			$280.1
Earnings as defined:
Pretax income from continuing operations		$997.9	$1,152.6			$786.0			$693.8			$601.6			$555.6			$535.4
Total fixed charges above	250.3		335.8		332.0			316.1			311.1			297.0			280.1
Pretax equity in (earnings) losses of investees	0.5		0.0		(1.4		)	(3.2		)	(3.3		)	(2.9		)	(1.1		)
Cash distributions from equity investees	3.0		6.0		7.4			9.6			3.3			3.6			4.8
Total Earnings (B)	$1,251.7		$1,494.4		$1,124.0				$1016.3			$912.7			$853.3			$819.2
Ratio of Earnings to Fixed Charges (B/A)	5.00		4.45		3.39			3.22			2.93			2.87			2.92

SCE&G:	Nine Months Ended September 30, 2015		Twelve Months Ended September 30, 2015		Years ended December 31,
Dollars in Millions					2014		2013		2012		2011		2010
Fixed Charges as defined:
Interest on debt		$191.6		$252.2		$237.6		$226.4		$217.4		$207.8		$192.4
Amortization of debt premium, discount and expense (net)	2.8		3.9		4.4		4.2		3.9		3.9		4.0
Interest component on rentals	3.1		4.2		4.0		4.5		3.2		3.6		3.1
Total Fixed Charges (A)		$197.5		$260.3		$246.0		$235.1		$224.5		$215.3		$199.5
Earnings as defined:
Pretax income from continuing operations		$600.9		$715.6		$676.0		$579.7		$509.5		$456.5		$433.6
Total fixed charges above	197.5		260.3		246.0		235.1		224.5		215.3		199.5
Pretax equity in (earnings) losses of investees	3.8		5.0		5.3		3.5		3.8		2.3		2.1
Total Earnings (B)		$802.2		$980.9		$927.3		$818.3		$737.8		$674.1		$635.2
Ratio of Earnings to Fixed Charges (B/A)	4.06		3.77		3.77		3.48		3.29		3.13		3.18

EX-31.01

Exhibit 31.01

CERTIFICATION

I, Kevin B. Marsh, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: November 6, 2015
	/s/Kevin B. Marsh
	Kevin B. Marsh
	Chairman of the Board, President, Chief Executive Officer and
	Chief Operating Officer

EX-31.02

Exhibit 31.02

CERTIFICATION

I, Jimmy E. Addison, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: November 6, 2015
	/s/Jimmy E. Addison
	Jimmy E. Addison
	Executive Vice President and Chief Financial Officer

EX-31.03

Exhibit 31.03

CERTIFICATION

I, Kevin B. Marsh, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: November 6, 2015
	/s/Kevin B. Marsh
	Kevin B. Marsh
	Chairman of the Board and Chief Executive Officer

EX-31.04

Exhibit 31.04

CERTIFICATION

I, Jimmy E. Addison, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: November 6, 2015
	/s/Jimmy E. Addison
	Jimmy E. Addison
	Executive Vice President and Chief Financial Officer

EX-32.01

Exhibit 32.01 

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of SCANA Corporation (the “Company”) on Form 10-Q for the quarter ended September 30, 2015 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), we certify pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

Date: November 6, 2015
/s/Kevin B. Marsh	/s/Jimmy E. Addison
Kevin B. Marsh	Jimmy E. Addison
Chairman of the Board, President, Chief Executive Officer	Executive Vice President and Chief Financial Officer
and Chief Operating Officer

EX-32.02

Exhibit 32.02

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of South Carolina Electric & Gas Company (the “Company”) on Form 10-Q for the quarter ended September 30, 2015 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), we certify pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

Date: November 6, 2015
/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

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

XML

COMMITMENTS AND CONTINGENCIES (Details) - USD ($)	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2013
Commitments and contingencies
Asset Retirement Obligation	$ 489,000,000	$ 563,000,000				$ 576,000,000
Asset Retirement Obligation, Liabilities Incurred	0	3,000,000
Asset Retirement Obligation, Liabilities Settled	(15,000,000)	(6,000,000)
Asset Retirement Obligation, Accretion Expense	20,000,000	26,000,000
Asset Retirement Obligation, Revision of Estimate	$ (79,000,000)	(36,000,000)
Nuclear Generation
Emission Rate Standard For Coal Fired Power Plants Under Clean Air Act	1,400
Emission Rate Standard For Gas Fired Power Plants Under Clean Air Act	1,000
Goal For Reduced Carbon Dioxide Emissions From 2005 Levels By 2030 Under Clean Air Act	32.00%
NPDES permit renewal permit period	five
Forecasted Incremental Capital Costs Associated With Schedule Delays, 2015 Petition	$ 539,000,000
EPC Contract Amendment, New Nuclear Construction Completion Bonus	151,000,000
EPC Contract Amendment, Fixed Price Option, Increase In Total New Nuclear Project Cost	774,000,000
Regulatory Assets, Noncurrent	1,884,000,000	1,823,000,000
Asset Retirement Obligation Other Conditional Obligations	315,000,000	362,000,000
SCEG
Commitments and contingencies
Asset Retirement Obligation	460,000,000	536,000,000				$ 547,000,000
Asset Retirement Obligation, Liabilities Incurred	0	3,000,000
Asset Retirement Obligation, Liabilities Settled	(15,000,000)	(6,000,000)
Asset Retirement Obligation, Accretion Expense	18,000,000	25,000,000
Asset Retirement Obligation, Revision of Estimate	(79,000,000)	(33,000,000)
Nuclear Insurance
Federal Limit on Public Liability Claims from Nuclear Incident Approximate	12,900,000,000
Maximum Insurance Coverage for each Nuclear Plant by ANI	375,000,000
Maximum liability assessment per reactor for each nuclear incident	127,300,000
Maximum Federal Limit on Public Liability Claims Per Incident for Each Year	12,600,000
Maximum yearly assessment per reactor	18,900,000
Maximum Federal Limit on Public Liability Claims per Reactor for each Nuclear Incident at 2/3	$ 84,800,000
Inflation adjustment period for nuclear insurance	5
Maximum retrospective insurance premium per nuclear incident	$ 45,900,000
Maximum amount of coverage to nuclear facility for property damage and outage costs	2,750,000,000
Maximum amount of coverage for accidental property damage	500,000,000
Maximum loss for a single nuclear incident	$ 2,750,000,000
Environmental
Number of MGP decommissioned sites that contain residues of byproduct chemicals	4
Site Contingency MGP Estimated Environmental Remediation Costs	$ 19,000,000
Deferred costs net of costs previously recovered through rates and insurance settlements included in regulatory assets	$ 34,700,000
Nuclear Generation
Current ownership share in New Unit	55.00%
Total additional ownership in new units	5.00%
Additional ownership in new units	1.00%
Additional ownership in new units, dollars	$ 750,000,000
Emission Rate Standard For Coal Fired Power Plants Under Clean Air Act	1,400
Emission Rate Standard For Gas Fired Power Plants Under Clean Air Act	1,000
Goal For Reduced Carbon Dioxide Emissions From 2005 Levels By 2030 Under Clean Air Act	0.00%
EPC Contract Amendment, Settlement Of Outstanding New Nuclear Construction Disputes	$ 165,000,000
EPC Contract Amendment, Credit Applied To Target Component Of New Units Contract Price	27,000,000
EPC Contract Amendment, Cap On Delay Oriented Liquidated Damages Per New Nuclear Unit	255,000,000
EPC Contract Amendment, Revised Construction Milestone Payment Schedule, Per Month	55,000,000
EPC Contract Amendment, Increase In Total New Nuclear Project Cost	286,000,000
Total New Nuclear Project Cost Approved By SCPSC In September 2015	7,000,000,000
EPC Contract Amendment, Fixed Price Option, Project Cost Approved By SCPSC Including Fixed Option Price Increase	7,600,000,000.0
EPC Contract Amendment, Total New Nuclear Project Cost Approved By SCPSC Including Amendment Increase	7,000,000,000
EPC Contract Amendment, Fixed Price Option, Price For New Nuclear Construction After June 2015	3,345,000,000.000
EPC Contract Amendment, Fixed Price Option, Cap On Delay Oriented Liquidated Damages Per New Nuclear Unit	186,000,000
EPC Contract Amendment, Fixed Price Option, New Nuclear Construction Completion Bonus	83,000,000
Regulatory Assets, Noncurrent	1,808,000,000	1,745,000,000
Asset Retirement Obligation Nuclear Decommissioning	174,000,000	201,000,000
Asset Retirement Obligation Other Conditional Obligations	286,000,000	$ 335,000,000
Summer Station New Units [Domain]
Nuclear Insurance
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	3,300,000,000
jointly owned utility plant ownership, construction financing cost	$ 2,425,000,000
Nuclear Generation
Jointly Owned Utility Plant, Proportionate Ownership Share	55.00%
Jointly Owned Utility Plant, Additional Ownership Of New Units	5.00%
Nuclear Production Tax Credits	$ 1,400,000,000
Nuclear Production Tax Credit realization period	8
EPC Contract Amendment, Settlement Of Outstanding New Nuclear Construction Disputes	$ 300,000,000
EPC Contract Amendment, Credit Applied To Target Component Of New Units Contract Price	50,000,000
EPC Contract Amendment, Cap On Delay Oriented Liquidated Damages Per New Nuclear Unit	463,000,000
EPC Contract Amendment, New Nuclear Construction Completion Bonus	275,000,000
EPC Contract Amendment, Revised Construction Milestone Payment Schedule, Per Month	100,000,000
EPC Contract Amendment, Fixed Price Option, Price For New Nuclear Construction After June 2015	6,082,000,000.000
EPC Contract Amendment, Fixed Price Option, Cap On Delay Oriented Liquidated Damages Per New Nuclear Unit	338,000,000
EPC Contract Amendment, Fixed Price Option, New Nuclear Construction Completion Bonus	$ 150,000,000
Summer Station New Units [Domain] | SCEG
Nuclear Generation
Jointly Owned Utility Plant, Proportionate Ownership Share	55.00%
Nuclear Production Tax Credits	$ 1,400,000,000
Nuclear Production Tax Credit realization period	8
Capital costs, owners [Domain]
Nuclear Generation
Forecasted incremental capital costs, 2015 petition	$ 245,000,000
Forecasted Total Capital Costs, 2015 Petition	5,200,000,000.0
Capital costs, owners [Domain] | SCEG
Nuclear Generation
Forecasted incremental capital costs, 2015 petition	245,000,000
Capital costs, Other [Domain] [Domain]
Nuclear Generation
Forecasted incremental capital costs, 2015 petition	453,000,000
Forecasted Total Capital Costs, 2015 Petition	6,800,000,000.0
Capital costs, Other [Domain] [Domain] | SCEG
Nuclear Generation
Forecasted incremental capital costs, 2015 petition	$ 453,000,000
Scenario, Forecast [Member] | SCEG
Nuclear Generation
Additional ownership in new units			2.00%	2.00%	1.00%

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details 2) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014	Sep. 30, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	$ 6,034.3	$ 5,697.2
Long-term Debt, Fair Value		6,592.1	$ 6,623.3
SCEG
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	4,801.0	4,308.6
Long-term Debt, Fair Value	$ 5,277.6	$ 5,070.9

XML

RATE AND OTHER REGULATORY MATTERS (Details)	3 Months Ended			6 Months Ended	9 Months Ended		12 Months Ended
	Sep. 30, 2015 USD ($) MW	Sep. 30, 2014 USD ($)	Mar. 31, 2014	Jun. 30, 2015	Sep. 30, 2015 USD ($) MW $ / shares	Sep. 30, 2014 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Sep. 30, 2013 USD ($)
Rate Matters [Line Items]
Depreciation Study 2015, Effect Of Lower Depreciation Rates Annually, Dollars					$ 29,000,000
Depreciation Study 2015, Effect Of Lower Depreciation Rates Annually, Per Share | $ / shares					$ 0.12
Depreciation Study 2015, Effect Of Lower Depreciation Rates For YTD September 2015, Dollars					$ 22,000,000
Depreciation Study 2015, Effect Of Lower Depreciation Rates for YTD September 2015, Per Share | $ / shares					$ 0.09
Depreciation Study 2015, Undercollected Fuel Amount Offset by Lower Depreciation Rates, Dollars					$ 14,500,000.0
Depreciation Study 2015, Undercollected Fuel Amount Offset by Lower Depreciation Rates, Per Share | $ / shares					$ 0.06
Depreciation Study 2015, Increase in Net Income	$ 4,500,000				$ 4,500,000.0
Carrying cost recovery					(9,000,000)	$ (7,000,000)
Regulatory Assets, Noncurrent	1,884,000,000				$ 1,884,000,000		$ 1,823,000,000
Public Utilities Base Fuel under Collected Balance Recovery Period					12
Amortization Period For Carrying Cost On Accumlated Deferred Income Tax Assets Associated With New Units					10
SCEG
Rate Matters [Line Items]
Amounts Recovered Through Electric Rates to offset Nuclear Related Outage Costs					$ 17,200,000
Fuel Costs					10,300,000
Undercollected balance fuel	$ 46,000,000				$ 46,000,000
Capacity of renewable energy facilities by 2020 | MW	85				85
Capacity of renewable energy facilities by 2016 | MW	30				30
Depreciation Study 2015, Effect Of Lower Depreciation Rates Annually, Dollars					$ 29,000,000
Depreciation Study 2015, Effect Of Lower Depreciation Rates for YTD September 2015, Per Share | $ / shares					$ 22,000,000
Depreciation Study 2015, Undercollected Fuel Amount Offset by Lower Depreciation Rates, Dollars					$ 14,500,000.0
Depreciation Study 2015, Increase in Net Income	$ 4,500,000				4,500,000.0
Carrying costs on deferred income tax assets	2,400,000	$ 1,600,000			6,500,000	4,100,000
Carrying cost recovery					(9,000,000)	(7,000,000)
Regulatory Assets, Noncurrent	1,808,000,000				$ 1,808,000,000		1,745,000,000
Allowable return on common equity (as a percent)				11.00%	11.00%
Demand Side Management Program Costs, Noncurrent	32,000,000	$ 15,400,000			$ 32,000,000	$ 15,400,000			$ 16,900,000
Increase (decrease) in retail electric rate requested under the BLRA					$ 65,000,000		$ 66,000,000	$ 67,200,000
Public Utilities, Percent Increase (Decrease) in Retail Electric Rates					0.00%		0.00%	2.90%
Public Utilities, Percent Increase (Decrease) in Retail Natural Gas Rates							0.60%
Public Utilities changes in Retail Natural Gas Rates Approved under RSA							$ 2,600,000
Public Utilities, Rate Calculation Basis					12-month rolling average
Public Utilities Base Fuel under Collected Balance Recovery Period					12
Derivative, Gain on Derivative							17,800,000
Storm Damage Reserve Cost Applied							5,000,000
Demand side management recovery period					5
Amortization Period For Carrying Cost On Accumlated Deferred Income Tax Assets Associated With New Units					10
Pipeline Integrity Management Costs, Annual					$ 1,900,000.0
Amount Allowed to be Recovered through Electric Rates to Offset Incremental Storm Damage Costs					$ 100,000,000
PSNC Energy
Rate Matters [Line Items]
Public Utilities, Rate Calculation Basis			12
Pension costs, electric [Member] | SCEG
Rate Matters [Line Items]
Regulatory Noncurrent Asset Amortization Period					30 years
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority	63,000,000				$ 63,000,000
Pension costs, gas [Member] | SCEG
Rate Matters [Line Items]
Regulatory Noncurrent Asset Amortization Period								14 years
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority	14,000,000				14,000,000
Pension Costs [Member]
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	328,000,000				328,000,000		350,000,000
Pension Costs [Member] | SCEG
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	296,000,000				$ 296,000,000		310,000,000
Regulatory Noncurrent Asset Amortization Period					12 years			30 years
Other Regulatory Assets [Member]
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	43,000,000				$ 43,000,000		35,000,000
Regulatory Noncurrent Asset Amortization Period					30 years
Other Regulatory Assets [Member] | SCEG
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	45,000,000				$ 45,000,000		35,000,000
Deferred Pollution Control Costs
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	35,000,000				35,000,000		36,000,000
Deferred Pollution Control Costs | SCEG
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	35,000,000				35,000,000		36,000,000
Franchise agreement Costs
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	23,000,000				23,000,000		26,000,000
Franchise agreement Costs | SCEG
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	$ 23,000,000				23,000,000		$ 26,000,000
Planned major maintenance [Member] | SCEG
Rate Matters [Line Items]
Amounts Recovered through Electric Rates to offset Turbine Expense					18,400,000
Storm damage reserve [Member]
Rate Matters [Line Items]
Amount Allowed to be Recovered through Electric Rates to Offset Incremental Storm Damage Costs					$ 100,000,000

XML

LONG-TERM AND SHORT-TERM DEBT (Tables)

9 Months Ended

Sep. 30, 2015

Short-term Debt [Line Items]

Schedule of Line of Credit Facilities [Table Text Block]

SCANA, SCE&G (including Fuel Company) and PSNC Energy had available the following committed LOC, and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations: 

	SCANA						SCE&G						PSNC Energy
Millions of dollars	September 30, 2015			December 31, 2014			September 30, 2015			December 31, 2014			September 30, 2015			December 31, 2014
Lines of credit:
Total committed long-term	$	300		$	300		$	1,400		$	1,400		$	100		$	100
Outstanding commercial paper ( 270 or fewer days)	$	14		$	179		$	234		$	709		$	16		$	30
Weighted average interest rate	0.66		%	0.54		%	0.44		%	0.52		%	0.45		%	0.65		%
Letters of credit supported by LOC	$	3		$	3		$	0.3		$	0.3		—			—
Available	$	283		$	118		$	1,166		$	691		$	84		$	70

SCEG

Short-term Debt [Line Items]

Schedule of Line of Credit Facilities [Table Text Block]

SCE&G (including Fuel Company) had available the following committed LOC, and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations:

Millions of dollars	September 30, 2015			December 31, 2014
Lines of credit:
Total committed long-term	$	1,400		$	1,400
Outstanding commercial paper (270 or fewer days)	$	234		$	709
Weighted average interest rate	0.44		%	0.52		%
Letters of credit supported by LOC	$	0.3		$	0.3
Available	$	1,166		$	691

XML

AFFILIATED TRANSACTIONS -SCEG (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Canadys Refined Coal [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction	$ 65.9	$ 82.0	$ 185.1	$ 190.9
Due to Affiliate, Current	21.8		21.8		$ 27.9
Due from Affiliate, Current	$ 21.6		$ 21.6		27.8
Equity Method Investment, Ownership Percentage	40.00%		40.00%
CGT [Member]
Related Party Transaction [Line Items]
Related Party Transaction Purchases from Related Party		6.9	$ 3.4	21.6
Due to Affiliate, Current					3.3
Due from Affiliate, Current		0.0		0.0	1.2
Energy Marketing [Member]
Related Party Transaction [Line Items]
Due to Affiliate, Current	$ 9.6		9.6		12.6
Cost of Natural Gas Purchases	34.0	46.8	101.4	154.1
Canadys Refined Coal [Member]
Related Party Transaction [Line Items]
Related Party Transaction Purchases from Related Party	66.3	82.4	186.0	191.9
SCANA Services [Member]
Related Party Transaction [Line Items]
Due to Affiliate, Current	37.2		37.2		$ 47.3
Related Party Transaction, Expenses from Transactions with Related Party	$ 80.8	$ 65.0	$ 226.0	$ 211.4

XML

DERIVATIVE FINANCIAL INSTRUMENTS On Income Statement (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Derivative [Line Items]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	$ (7.0)	$ (2.0)	$ (8.0)	$ (3.0)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	$ (3.0)	$ (2.0)	$ (16.0)	$ (1.0)
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant	insignificant	insignificant	insignificant
Commodity Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 1.0	$ 0.0	$ 10.0	$ (4.0)
Commodity Contract | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	(4.0)	(2.0)	(5.0)	1.0
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	2.0	2.0	6.0	5.0
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)	0.0	(3.0)	(4.0)
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	(116.0)	(35.0)	(79.0)	(220.0)
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	(3.0)	(1.0)	(3.0)	(5.0)
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	5.0	5.0	60.0
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			4.0
Gas Purchased for Resale [Member] [Member] | Commodity Contract | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(1.0)	0.0	(10.0)	4.0
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)	(6.0)	(5.0)
Interest Expense [Member] | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred			0.6
Interest Expense [Member] | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred			2.3
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	$ (1.0)	$ (1.0)	$ (2.0)	$ (2.0)
SCEG
Derivative [Line Items]
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant	insignificant	insignificant	insignificant
SCEG | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	$ (116.0)	$ (35.0)	$ (79.0)	$ (220.0)
SCEG | Other Nonoperating Income (Expense) [Member] | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	0.0	5.0	5.0	60.0
SCEG | Interest Expense [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income Effective Portion, Net	(1.0)	(1.0)	(2.0)	(2.0)
SCEG | Interest Expense [Member] | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	$ (3.0)	$ (1.0)	(3.0)	$ (5.0)
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred			0.6
SCEG | Interest Expense [Member] | Interest Rate Contract [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred			$ 2.3

XML

LONG-TERM AND SHORT-TERM DEBT (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended		9 Months Ended
	Mar. 31, 2015	Jun. 30, 2015	Jun. 30, 2014	Sep. 30, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				$ 1,800.0
Commercial Paper Maximum Term				270
Number of other banks (in entities)				2
Long-term Debt, Current Maturities				$ 16.0	$ 166.0
Debt Instrument, Interest Rate Terms	0.077	.051
Junior Subordinated Notes	$ 150.0
Credit Suisse AG, Cayman Islands Branch (Member)
Debt Instrument [Line Items]
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				8.90%
Branch Banking Trust Company [Member]
Debt Instrument [Line Items]
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				6.30%
SCE&G (including Fuel Company)
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				$ 1,400.0	1,400.0
Commercial Paper				$ 234.0	$ 709.0
Debt, Weighted Average Interest Rate				0.44%	0.52%
Letters of Credit Outstanding, Amount				$ 0.3	$ 0.3
Line of Credit Facility, Remaining Borrowing Capacity				1,166.0	691.0
SCEG
Debt Instrument [Line Items]
Proceeds from Issuance of First Mortgage Bond		$ 500.0	$ 300.0
Line of Credit Facility, Maximum Borrowing Capacity				1,200.0
Long-term Debt, Current Maturities				10.0	10.0
Debt Instrument, Face Amount				$ 67.8
Debt Instrument, Interest Rate Terms		0.051	.045
SCEG | Branch Banking Trust Company [Member]
Debt Instrument [Line Items]
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				8.90%
PSNC Energy [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				$ 100.0	100.0
Commercial Paper				16.0	$ 30.0
Debt, Weighted Average Interest Rate					0.65%
Letters of Credit Outstanding, Amount				0.0	$ 0.0
Line of Credit Facility, Remaining Borrowing Capacity				84.0	$ 70.0
Fuel Company
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				$ 500.0

XML

EMPLOYEE BENEFIT PLANS (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2013
Pension and Other Postretirement Benefit Plans
Pension Contributions			No
Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	$ 6.6	$ 5.0	$ 18.1	$ 15.0
Interest cost	9.6	9.9	28.7	30.3
Expected return on assets	(15.5)	(16.4)	(46.5)	(50.0)
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	1.0	1.1	3.0	3.1
Defined Benefit Plan, Actuarial Net (Gains) Losses	3.2	0.9	10.2	3.5
Defined Benefit Plan, Net Periodic Benefit Cost	4.9	0.5	13.5	1.9
Other Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	1.2	0.9	4.0	3.4
Interest cost	2.8	2.8	8.6	9.0
Expected return on assets	0.0	0.0	0.0	0.0
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	0.1	0.1	0.3	0.3
Defined Benefit Plan, Actuarial Net (Gains) Losses	0.4	(0.2)	1.5	0.0
Defined Benefit Plan, Net Periodic Benefit Cost	4.5	3.6	$ 14.4	12.7
SCEG
Pension and Other Postretirement Benefit Plans
Pension Contributions			No
SCEG | Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	5.3	4.0	$ 14.5	12.0
Interest cost	8.1	8.4	24.1	25.6
Expected return on assets	(13.0)	(13.9)	(39.1)	(42.2)
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	0.8	0.9	2.5	2.6
Defined Benefit Plan, Actuarial Net (Gains) Losses	2.7	0.8	8.6	3.0
Defined Benefit Plan, Net Periodic Benefit Cost	3.9	0.2	10.6	1.0
SCEG | Other Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	1.0	0.7	3.2	2.7
Interest cost	2.2	2.3	6.8	7.1
Expected return on assets	0.0	0.0	0.0	0.0
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	0.1	0.0	0.2	0.2
Defined Benefit Plan, Actuarial Net (Gains) Losses	0.3	(0.2)	1.2	0.0
Defined Benefit Plan, Net Periodic Benefit Cost	$ 3.6	$ 2.8	$ 11.4	$ 10.0
Pension Costs [Member] | SCEG
Components of Net Periodic Benefit Cost
Regulatory Noncurrent Asset, Amortization Period			12 years		30 years

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

XML

DERIVATIVE FINANCIAL INSTRUMENTS Derivative Financial Instruments (Credit Risk) (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	$ 148.4	$ 152.4
Additional Collateral, Aggregate Fair Value	69.1	129.8
Derivative, Net Liability Position, Aggregate Fair Value	217.5	282.2
Cash collateral to request from interest rate derivative counterparty	2.8
LetterofCreditAvailableCommodityDerivatives,assetposition	3.0	9.2
Commodity Derivative, net asset position	15.0	20.0
Interest Rate Derivative, net asset position	2.8
SCEG
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	108.9	107.1
Additional Collateral, Aggregate Fair Value	65.8	125.9
Derivative, Net Liability Position, Aggregate Fair Value	174.7	$ 233.0
Cash collateral to request from interest rate derivative counterparty	2.8
Interest Rate Derivative, net asset position	$ 2.8

XML

COMMITMENTS AND CONTINGENCIES Asset Retirement Obligation (Tables)

9 Months Ended

Sep. 30, 2015

Change in Asset Retirement Obligation [Line Items]

Change in Asset Retirement Obligation [Table Text Block]

A reconciliation of the beginning and ending carrying amount of asset retirement obligations is as follows:

Millions of dollars	September 30, 2015			December 31, 2014
Beginning balance	$	563		$	576
Liabilities incurred	—			3
Liabilities settled	(15		)	(6		)
Accretion expense	20			26
Revisions in estimated cash flows	(79		)	(36		)
Ending balance	$	489		$	563

SCEG

Change in Asset Retirement Obligation [Line Items]

Schedule of Change in Asset Retirement Obligation [Table Text Block]

A reconciliation of the beginning and ending carrying amount of asset retirement obligations is as follows:

Millions of dollars	September 30, 2015			December 31, 2014
Beginning balance	$	536		$	547
Liabilities incurred	—			3
Liabilities settled	(15		)	(6		)
Accretion expense	18			25
Revisions in estimated cash flows	(79		)	(33		)
Ending balance	$	460		$	536

XML

EMPLOYEE BENEFIT PLANS (Tables)

9 Months Ended

Sep. 30, 2015

Pension and Other Postretirement Benefit Plans

Schedule of Net Benefit Costs [Table Text Block]

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2015			2014			2015		2014
Three months ended September 30,
Service cost	$	6.6		$	5.0		$	1.2	$	0.9
Interest cost	9.6			9.9			2.8		2.8
Expected return on assets	(15.5		)	(16.4		)	—		—
Prior service cost amortization	1.0			1.1			0.1		0.1
Amortization of actuarial losses (gains)	3.2			0.9			0.4		(0.2		)
Net periodic benefit cost	$	4.9		$	0.5		$	4.5	$	3.6

Nine months ended September 30,
Service cost	$	18.1		$	15.0		$	4.0	$	3.4
Interest cost	28.7			30.3			8.6		9.0
Expected return on assets	(46.5		)	(50.0		)	—		—
Prior service cost amortization	3.0			3.1			0.3		0.3
Amortization of actuarial losses	10.2			3.5			1.5		—
Net periodic benefit cost	$	13.5		$	1.9		$	14.4	$	12.7

SCEG

Pension and Other Postretirement Benefit Plans

Schedule of Net Benefit Costs [Table Text Block]

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2015			2014			2015		2014
Three months ended September 30,
Service cost	$	5.3		$	4.0		$	1.0	$	0.7
Interest cost	8.1			8.4			2.2		2.3
Expected return on assets	(13.0		)	(13.9		)	—		—
Prior service cost amortization	0.8			0.9			0.1		—
Amortization of actuarial losses (gains)	2.7			0.8			0.3		(0.2		)
Net periodic benefit cost	$	3.9		$	0.2		$	3.6	$	2.8

Nine months ended September 30,
Service cost	$	14.5		$	12.0		$	3.2	$	2.7
Interest cost	24.1			25.6			6.8		7.1
Expected return on assets	(39.1		)	(42.2		)	—		—
Prior service cost amortization	2.5			2.6			0.2		0.2
Amortization of actuarial losses	8.6			3.0			1.2		—
Net periodic benefit cost	$	10.6		$	1.0		$	11.4	$	10.0

XML

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

XML

SEGMENT OF BUSINESS INFORMATION (Tables)

9 Months Ended

Sep. 30, 2015

Segment Reporting Information [Line Items]

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

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

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

Three Months Ended September 30, 2014
Electric Operations	$	739		$	1		$	275		n/a
Gas Distribution	127			—			(6		)	n/a
Retail Gas Marketing	68			—			n/a			$	(3	)
Energy Marketing	182			47			n/a			(2		)
All Other	9			103			7			(5		)
Adjustments/Eliminations	(4		)	(151		)	(7		)	154
Consolidated Total	$	1,121		$	—		$	269		$	144

Nine Months Ended September 30, 2014
Electric Operations	$	2,027		$	5		$	616	n/a
Gas Distribution	728			—			98		n/a
Retail Gas Marketing	367			—			n/a		$	16
Energy Marketing	602			154			n/a		5
All Other	27			317			21		(3		)
Adjustments/Eliminations	(15		)	(476		)	37		415
Consolidated Total	$	3,736		$	—		$	772	$	433

	September 30,		December 31,
Segment Assets	2015		2014
Electric Operations	$	10,531	$	10,182
Gas Distribution	2,498		2,487
Retail Gas Marketing	107		140
Energy Marketing	102		150
All Other	998		1,474
Adjustments/Eliminations	2,270		2,419
Consolidated Total	$	16,506	$	16,852

SCEG

Segment Reporting Information [Line Items]

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

.

Millions of dollars	External Revenue		Operating Income			Earnings Available to Common Shareholder
Three Months Ended September 30, 2015
Electric Operations	$	743	$	313		n/a
Gas Distribution	63		(6		)	n/a
Adjustments/Eliminations	—		—			$	164
Consolidated Total	$	806	$	307		$	164

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

Three Months Ended September 30, 2014
Electric Operations	$	740	$	274		n/a
Gas Distribution	72		(2		)	n/a
Adjustments/Eliminations	—		—			$	154
Consolidated Total	$	812	$	272		$	154

Nine Months Ended September 30, 2014
Electric Operations	$	2,032	$	616	n/a
Gas Distribution	337		40		n/a
Adjustments/Eliminations	—		—		$	374
Consolidated Total	$	2,369	$	656	$	374

Segment Assets	September 30, 2015		December 31, 2014
Electric Operations	$	10,531	$	10,182
Gas Distribution	749		721
Adjustments/Eliminations	3,032		3,204
Consolidated Total	$	14,312	$	14,107

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Dispositions (Tables)

9 Months Ended

Sep. 30, 2015

Disposal groups [Abstract]

Schedule of Disposal Group, Held for Sale [Table Text Block]

Millions of dollars	CGT		SCI		Total
Assets Held for Sale
Utility Plant, Net	$	288.4	—		$	288.4
Nonutility Property and Investments, Net	0.6		$	40.1	40.7
Current Assets	6.5		3.9		10.4
Deferred Debits and Other Assets	0.9		0.2		1.1
Total Assets Held for Sale	$	296.4	$	44.2	$	340.6
Liabilities Held for Sale
Current Liabilities	$	3.5	$	2.2	$	5.7
Deferred Credits and Other Liabilities	42.9		3.1		46.0
Total Liabilities Held for Sale	$	46.4	$	5.3	$	51.7

XML

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

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) $ in Millions	9 Months Ended
	Sep. 30, 2015 USD ($) MW	Dec. 31, 2014 USD ($)
Significant Accounting Policies
Property, Plant and Equipment, Net	$ 281.0	$ 284.0
SCEG
Significant Accounting Policies
Property, Plant and Equipment, Net	$ 67.0	$ 67.0
Genco
Significant Accounting Policies
Power Generation Capacity Megawatts | MW	605
Property, Plant and Equipment, Net	$ 489.0
PSNC Energy [Member]
Significant Accounting Policies
Percentage of natural gas inventory held by counterparties under asset management and supply service agreements (as a percent)	50.00%	48.00%
Natural gas inventory, carrying amount	$ 19.1	$ 26.1
PercentOfStorageFeesCreditedToRatePayers	75.00%

XML

DERIVATIVE FINANCIAL INSTRUMENTS (Details) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2015 USD ($) MMBTU	Dec. 31, 2014 USD ($) MMBTU
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	57,604,782	55,733,059
Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	9,270,000	6,840,000
Retail Gas Marketing
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	11,788,000	7,951,000
Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	36,546,782	40,942,059
Commodity Contract
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	25,393,500	18,237,720
Commodity Contract | Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	9,270,000	6,840,000
Commodity Contract | Retail Gas Marketing
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	11,788,000	7,951,000
Commodity Contract | Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	4,335,500	3,446,720
Energy Related Derivative [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	32,211,282	37,495,339
Energy Related Derivative [Member] | Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0	0
Energy Related Derivative [Member] | Retail Gas Marketing
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0	0
Energy Related Derivative [Member] | Energy Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	32,211,282	37,495,339
Energy Related Derivative [Member] | Basis Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	1,246,230	933,893
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Interest Rate Derivatives [Abstract]
Derivative, Notional Amount	$ 1,200.0	$ 1,100.0
Cash Flow Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Interest Rate Derivatives [Abstract]
Derivative, Notional Amount	120.0	124.4
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Interest Rate Derivatives [Abstract]
Derivative, Notional Amount	1,200.0	1,100.0
SCEG | Cash Flow Hedging [Member] | Interest Rate Swap [Member]
Interest Rate Derivatives [Abstract]
Derivative, Notional Amount	$ 36.4	$ 36.4

XML

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

XML

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

XML

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

XML

RATE AND OTHER REGULATORY MATTERS (Details 3) - USD ($) $ in Millions	3 Months Ended	6 Months Ended	9 Months Ended	12 Months Ended
	Mar. 31, 2014	Jun. 30, 2015	Sep. 30, 2015	Dec. 31, 2014	Dec. 31, 2013	Sep. 30, 2014	Sep. 30, 2013
Regulatory Liabilities [Line Items]
Regulatory Assets, Noncurrent			$ 1,884.0	$ 1,823.0
Regulatory Liabilities			859.0	$ 814.0
SCEG
Regulatory Liabilities [Line Items]
Public Utilities, Percent Increase (Decrease) in Retail Natural Gas Rates				0.60%
Storm Damage Reserve Applied To Offset Net Lost Margin Related To DSM	$ 5.0
Regulatory Assets, Noncurrent			1,808.0	$ 1,745.0
Public Utilities Increase (Decrease) in Retail Electric Rates Approved under BLRA			$ 65.0	66.0	$ 67.2
Public Utilities, Authorized Allowable Return on Common Equity, Percentage		11.00%	11.00%
Demand Side Management Program Costs, Noncurrent			$ 32.0			$ 15.4	$ 16.9
Regulatory Liabilities			641.0	610.0
Annual Storm Damage Costs not offset by Amounts Recovered through Electric Rates			2.5
Amount Allowed to be Recovered through Electric Rates to Offset Incremental Storm Damage Costs			100.0
Asset Retirement Obligation Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities			729.0	703.0
Asset Retirement Obligation Costs [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities			520.0	505.0
Storm damage reserve [Member]
Regulatory Liabilities [Line Items]
Storm Damage Reserve Applied To Offset Net Lost Margin Related To DSM				5.0
Regulatory Liabilities			6.0	6.0
Annual Storm Damage Costs not offset by Amounts Recovered through Electric Rates			2.5
Amount Allowed to be Recovered through Electric Rates to Offset Incremental Storm Damage Costs			100.0
Storm damage reserve [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities			6.0	6.0
Deferred gains on interest rate derivatives [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities			87.0	82.0
Deferred gains on interest rate derivatives [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities			87.0	82.0
Deferred Income Tax Charges [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities			22.0	22.0
Deferred Income Tax Charges [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities			16.0	17.0
Planned major maintenance [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities			12.0	0.0
Planned major maintenance [Member] | SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities			$ 12.0	$ 0.0

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

9 Months Ended

Sep. 30, 2015

Significant Accounting Policies

Use of Estimates

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Plant to be retired [Policy Text Block]

Plant to be Retired

At December 31, 2014, SCE&G expected to retire three units that are or were coal-fired by 2020, which was prior to the end of the previously estimated useful lives over which the units were being depreciated. As such, these units were identified as Plant to be Retired. In the third quarter of 2015, in connection with the adoption of a customary depreciation study and related analysis, SCE&G determined that these three units would not likely be retired by 2020 (see Note 2), and their depreciation rates were set to recover the units' net carrying value over their respective revised useful lives. Accordingly, the net carrying value of these units is no longer classified as Plant to be Retired at September 30, 2015.

Asset Management and Supply Service Agreements

Asset Management and Supply Service Agreements

PSNC Energy utilizes asset management and supply service agreements with counterparties for certain natural gas storage facilities.  Such counterparties held 50% and 48% of PSNC Energy’s natural gas inventory at September 30, 2015

and December 31, 2014, respectively, with a carrying value of $19.1 million and $26.1 million, respectively, through either capacity release or agency relationships.  Under the terms of the asset management agreements, PSNC Energy receives storage asset management feesof which 75% are credited to rate payers. No fees are received under supply service agreements. The agreements, which expired on March 31, 2015, were replaced with similar agreements scheduled to expire March 31, 2017.

Income Statement policy [Policy Text Block]

Income Statement Presentation

The Company presents the revenues and expenses of its regulated businesses and its retail natural gas marketing businesses (including those activities of segments described in Note 10) within operating income, and it presents all other activities within other income (expense). Consistent with this presentation, the gain on the sale of CGT is reflected within operating income and the gain on the sale of SCI is reflected within other income (expense).

SCEG

Significant Accounting Policies

Use of Estimates

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Consolidation, Variable Interest Entity, Policy [Policy Text Block]

Variable Interest Entities

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

GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $489 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission allowances. See also Note 4.

Plant to be retired [Policy Text Block]

Plant to be Retired

At December 31, 2014, SCE&G expected to retire three units that are or were coal-fired by 2020, which was prior to the end of the previously estimated useful lives over which the units were being depreciated. As such, these units were identified as Plant to be Retired. In the third quarter of 2015, in connection with the adoption of a customary depreciation study and related analysis, SCE&G determined that these three units would not likely be retired by 2020 (see Note 2), and their depreciation rates were set to recover the units' net carrying value over their respective revised useful lives. Accordingly, the net carrying value of these units is no longer classified as Plant to be Retired at September 30, 2015.

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COMMON EQUITY (Details) - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013
Schedule of Capitalization, Equity [Line Items]
Common Stock, Value, Outstanding	$ 2,391		$ 2,391		$ 2,378
Common Stock, Shares Authorized	200.0		200.0		200.0
COMMON EQUITY [Abstract]
Dividends declared			$ (234)	$ (223)
Stock Issued During Period, Shares, New Issues				1.0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	$ 146	$ 145	653	$ 432
Proceeds from Issuance of Common Stock			14	75
Stock Issued During Period, Value, New Issues			13	76
Stock Repurchase Program, Authorized Amount	(1)	(1)	(1)	(1)
Treasury Stock, Value	$ (11)	$ (10)	$ (11)	$ (10)	$ (10)	$ (9)
Common Stock, Shares, Outstanding	142.9	142.0	142.9	142.0	142.7	141.0
Stockholders' Equity before Treasury Stock	$ 2,402	$ 2,365	$ 2,402	$ 2,365	$ 2,388	$ 2,289
Retained Earnings, Unappropriated	3,098	2,654	3,098	2,654	2,684	2,444
Accumulated Other Comprehensive Income (Loss), Net of Tax	(70)		(70)		(75)
AOCI before Tax, Attributable to Parent	55	54	55	54	63
Other Comprehensive Income (Loss), Net of Tax	(3)	1	5	(1)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, before Reclassification Adjustments, Net of Tax	1		(3)	(1)
Defined Benefit Plan, Accumulated Benefit Obligation	(15)	(7)	(15)	(7)
Defined Benefit Plan, Benefit Obligation	3	1	3	1	(12)	(8)
AOCI Tax, Attributable to Parent						52
Income Available to Common Shareholders	149	144	648	433
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax	(4)	0	8	(2)
Common equity	5,419	4,948	5,419	4,948	4,987	4,664
AOCI Attributable to Parent [Member]
COMMON EQUITY [Abstract]
Accumulated Other Comprehensive Income (Loss), Net of Tax	70	61	70	61
AOCI before Tax, Attributable to Parent	(11)	(3)	(11)	(3)	$ (75)
AOCI Tax, Attributable to Parent						$ (60)
Reclassification out of Accumulated Other Comprehensive Income [Member]
COMMON EQUITY [Abstract]
AOCI before Tax, Attributable to Parent	$ (16)	$ (2)	$ (16)	$ (2)
SCEG
Schedule of Capitalization, Equity [Line Items]
Common Stock, Shares, Issued	40.3	40.3	40.3	40.3	40.3	40.3
Common Stock, Value, Outstanding	$ 2,756		$ 2,756		$ 2,560
Common Stock, Shares Authorized	50.0		50.0
COMMON EQUITY [Abstract]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ 167	$ 157	$ 405	$ 383
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax			0	0
Proceeds from Contribution from Parent, net of return of Proceeds			196	82
Dividends			(210)	(197)
Net Income (Loss) Attributable to Noncontrolling Interest	$ 3	3	11	9
Comprehensive Income (Loss), Net of Tax, Attributable to Parent			$ 405	383
Common Stock, Shares, Outstanding	40.3		40.3		40.3
Preferred Stock, Shares Authorized	20.0		20.0
Preferred Stock, Shares Outstanding	0.0		0.0
Preferred Stock, Value, Issued	$ 0		$ 0
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	5,148	4,757	5,148	4,757	$ 4,757	$ 4,489
Retained Earnings, Unappropriated	2,266		2,266		2,077
Accumulated Other Comprehensive Income (Loss), Net of Tax	(3)		$ (3)		(3)
Reclassifcations of deferred employee benefit costs			not significant
Common equity	5,019		$ 5,019		4,634
SCEG excluding VIEs [Member]
Schedule of Capitalization, Equity [Line Items]
Common Stock, Value, Outstanding	2,756	2,561	2,756	2,561	2,560	2,479
COMMON EQUITY [Abstract]
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax			0	0
Dividends			(205)	(192)
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	164	154	394	374
Retained Earnings, Unappropriated	2,266	2,078	2,266	2,078	2,077	1,896
Accumulated Other Comprehensive Income (Loss), Net of Tax	(3)	(3)	(3)	(3)	(3)	(3)
Income Available to Common Shareholders			394	374
Noncontrolling Interest [Member]
COMMON EQUITY [Abstract]
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders			(5)	(5)
Net Income (Loss) Attributable to Noncontrolling Interest			11	9
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	129	121	129	121	$ 123	$ 117
Interest Rate Contract
Schedule of Capitalization, Equity [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(2)	(2)	(6)	(5)
Commodity Contract
Schedule of Capitalization, Equity [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(1)	0	(10)	4
Accumulated Net Investment Gain (Loss) Attributable to Parent [Member] | Other Comprehensive Income (Loss) [Member]
COMMON EQUITY [Abstract]
AOCI before Tax, Attributable to Parent	8	3	8	3
Gain (Loss) on Derivative Instruments [Member] | Other Comprehensive Income Location [Domain]
COMMON EQUITY [Abstract]
AOCI before Tax, Attributable to Parent	(16)	(1)	(16)	(1)
Interest Expense [Member] | Cash Flow Hedging [Member] | Interest Rate Contract
Schedule of Capitalization, Equity [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	2	2	6	5
Gas Purchased for Resale [Member] [Member] | Cash Flow Hedging [Member] | Commodity Contract
Schedule of Capitalization, Equity [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 1	$ 0	$ 10	$ (4)

XML

COMMON EQUITY (Tables)

9 Months Ended

Sep. 30, 2015

Schedule of Capitalization, Equity [Line Items]

Schedule of Stockholders Equity [Table Text Block]

	Common Stock									Accumulated Other Comprehensive Income (Loss)
Millions	Shares	Outstanding Amount		Treasury Shares			Retained Earnings			Gains(Losses) on Cash Flow Hedges			Deferred Employee Benefit Plans			Total AOCI			Total Common Equity
Balance as of January 1, 2015	143	$	2,388	$	(10	)	$	2,684		$	(63	)	$	(12	)	$	(75	)	$	4,987
Net Income							648												648
Other Comprehensive Income (Loss):
Losses during the period										(8		)	(3		)	(11		)	(11		)
Reclassified from AOCI										16			—			16			16
Total Comprehensive Income (Loss)							648			8			(3		)	5			653
Issuance of Common Stock	—	14		(1		)													13
Dividends Declared							(234		)										(234		)
Balance as of September 30, 2015	143	$	2,402	$	(11	)	$	3,098		$	(55	)	$	(15	)	$	(70	)	$	5,419
Balance as of January 1, 2014	141	$	2,289	$	(9	)	$	2,444		$	(52	)	$	(8	)	$	(60	)	$	4,664
Net Income							433												433
Other Comprehensive Income:
Losses during the period										(3		)	—			(3		)	(3		)
Reclassified from AOCI										1			1			2			2
Total Comprehensive Income							433			(2		)	1			(1		)	432
Issuance of Common Stock	1	76		(1		)													75
Dividends Declared							(223		)										(223		)
Balance as of September 30, 2014	142	$	2,365	$	(10	)	$	2,654		$	(54	)	$	(7	)	$	(61	)	$	4,948

SCEG

Schedule of Capitalization, Equity [Line Items]

Schedule of Stockholders Equity [Table Text Block]

EQUITY

Changes in common equity during the nine months ended September 30, 2015 and 2014 were as follows:

	Common Stock			Retained			Accumulated Other Comprehensive			Noncontrolling			Total
Millions	Shares	Amount		Earnings			Income (Loss)			Interest			Equity
Balance at January 1, 2015	40	$	2,560	$	2,077		$	(3	)	$	123		$	4,757
Earnings available to common shareholder				394						11			405
Deferred cost of employee benefit plans							—						—
Total Comprehensive Income				394			—			11			405
Capital contributions from parent		196											196
Cash dividend declared				(205		)				(5		)	(210		)
Balance at September 30, 2015	40	$	2,756	$	2,266		$	(3	)	$	129		$	5,148
Balance at January 1, 2014	40	$	2,479	$	1,896		$	(3	)	$	117		$	4,489
Earnings available to common shareholder				374						9			383
Deferred cost of employee benefit plans							—						—
Total Comprehensive Income				374			—			9			383
Capital contributions from parent		82											82
Cash dividend declared				(192		)				(5		)	(197		)
Balance at September 30, 2014	40	$	2,561	$	2,078		$	(3	)	$	121		$	4,757

XML

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

XML

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

XML

EMPLOYEE BENEFIT PLANS

9 Months Ended

Sep. 30, 2015

Pension and Other Postretirement Benefit Plans

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS

Components of net periodic benefit cost recorded by the Company were as follows: 

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2015			2014			2015		2014
Three months ended September 30,
Service cost	$	6.6		$	5.0		$	1.2	$	0.9
Interest cost	9.6			9.9			2.8		2.8
Expected return on assets	(15.5		)	(16.4		)	—		—
Prior service cost amortization	1.0			1.1			0.1		0.1
Amortization of actuarial losses (gains)	3.2			0.9			0.4		(0.2		)
Net periodic benefit cost	$	4.9		$	0.5		$	4.5	$	3.6

Nine months ended September 30,
Service cost	$	18.1		$	15.0		$	4.0	$	3.4
Interest cost	28.7			30.3			8.6		9.0
Expected return on assets	(46.5		)	(50.0		)	—		—
Prior service cost amortization	3.0			3.1			0.3		0.3
Amortization of actuarial losses	10.2			3.5			1.5		—
Net periodic benefit cost	$	13.5		$	1.9		$	14.4	$	12.7

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

SCEG

Pension and Other Postretirement Benefit Plans

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS

Consolidated SCE&G participates in SCANA’s noncontributory defined benefit pension plan, which covers the majority of all regular, full-time employees, and also participates in SCANA’s unfunded postretirement health care and life insurance programs, which provide benefits to retired employees.  Components of net periodic benefit cost recorded by Consolidated SCE&G were as follows:

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2015			2014			2015		2014
Three months ended September 30,
Service cost	$	5.3		$	4.0		$	1.0	$	0.7
Interest cost	8.1			8.4			2.2		2.3
Expected return on assets	(13.0		)	(13.9		)	—		—
Prior service cost amortization	0.8			0.9			0.1		—
Amortization of actuarial losses (gains)	2.7			0.8			0.3		(0.2		)
Net periodic benefit cost	$	3.9		$	0.2		$	3.6	$	2.8

Nine months ended September 30,
Service cost	$	14.5		$	12.0		$	3.2	$	2.7
Interest cost	24.1			25.6			6.8		7.1
Expected return on assets	(39.1		)	(42.2		)	—		—
Prior service cost amortization	2.5			2.6			0.2		0.2
Amortization of actuarial losses	8.6			3.0			1.2		—
Net periodic benefit cost	$	10.6		$	1.0		$	11.4	$	10.0

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

XML

Document and Entity Information Document	9 Months Ended
	Sep. 30, 2015 shares
Entity Information [Line Items]
Entity Registrant Name	SCANA Corporation
Entity Central Index Key	0000754737
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding	142,916,917
SCEG
Entity Information [Line Items]
Entity Registrant Name	SOUTH CAROLINA ELECTRIC & GAS CO
Entity Central Index Key	0000091882
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding	40,296,147

XML

COMMITMENTS AND CONTINGENCIES

9 Months Ended

Sep. 30, 2015

Statement [Line Items]

Commitments and Contingencies Disclosure [Text Block]

COMMITMENTS AND CONTINGENCIES

Nuclear Insurance

Under Price-Anderson, SCE&G (for itself and on behalf of Santee Cooper, a one-third owner of Summer Station Unit 1) maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at SCE&G's nuclear power plant. Price-Anderson provides funds up to $12.9 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $375 million by ANI with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. Each reactor licensee is currently liable for up to $127.3 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $18.9 million of the liability per reactor would be assessed per year. SCE&G’s maximum assessment, based on its two-thirds ownership of Summer Station Unit 1, would be $84.8 million per incident, but not more than $12.6 million per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years.

SCE&G currently maintains insurance policies (for itself and on behalf of Santee Cooper) with NEIL. The policies provide coverage to Summer Station Unit 1 for property damage and outage costs up to $2.75 billion resulting from an event of nuclear origin. In addition, a builder's risk insurance policy has been purchased from NEIL for the construction of the New Units. This policy provides the owners of the New Units up to $500 million in limits of accidental property damage occurring during construction. The NEIL policies, in the aggregate, are subject to a maximum loss of $2.75 billion for any single loss occurrence. All of the NEIL policies permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $45.9 million.

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

New Nuclear Construction

In 2008, SCE&G, on behalf of itself and as agent for Santee Cooper, contracted with the Consortium for the design and construction of the New Units at the site of Summer Station.  

SCE&G's current ownership share in the New Units is 55%. As discussed below, under an agreement signed in January 2014 (and subject to customary closing conditions, including necessary regulatory approvals), SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper.

EPC Contract and BLRA Matters

The construction of the New Units and SCE&G’s related recovery of financing costs through rates is subject to review and approval by the SCPSC as provided for in the BLRA. Under the BLRA, the SCPSC has approved, among other things, a milestone schedule and a capital costs estimates schedule for the New Units. This approval constitutes a final and binding determination that the New Units are used and useful for utility purposes, and that the capital costs associated with the New Units are prudent utility costs and expenses and are properly included in rates, so long as the New Units are constructed or are being constructed within the parameters of the approved milestone schedule, including specified schedule contingencies, and the approved capital costs estimates schedule. Subject to the same conditions, the BLRA provides that SCE&G may apply to the SCPSC annually for an order to recover through revised rates SCE&G’s weighted average cost of capital applied to all or part of the outstanding balance of construction work in progress concerning the New Units. Such annual rate changes are described in Note 2. As of September 30, 2015, SCE&G’s investment in the New Units, including related transmission, totaled $3.3 billion, for which the financing costs on $2.4 billion have been reflected in rates under the BLRA.

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

Since the settlement of delay-related claims in 2012, the Consortium has continued to experience delays in the schedule, including those related to fabrication and delivery of sub-modules for the New Units. The fabrication and delivery of sub-modules have been and remain focus areas of the Consortium. Shield building panels are considered critical path items for both New Units, and the current schedule for production of such panels will require mitigation to support the updated substantial completion dates (see below).

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

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

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

On October 27, 2015, SCE&G, Santee Cooper and the Consortium reached a settlement regarding the above mentioned disputes, and the EPC Contract was amended. The October 2015 Amendment will become effective upon the consummation of the acquisition by WEC of the stock of Stone & Webster from CB&I, and will become null and void in the event such acquisition is not consummated by March 31, 2016. Following that acquisition, Stone & Webster will continue to be a member of the Consortium as a subsidiary of WEC rather than CB&I, and WEC intends to engage Fluor Corporation or its affiliate(s) as a subcontracted construction manager.

Among other things, upon effectiveness, the October 2015 Amendment would (i) resolve by settlement and release substantially all outstanding disputes between SCE&G and the Consortium, in exchange for (a) an additional cost to be paid by SCE&G and Santee Cooper of $300 million (SCE&G’s 55% portion being $165 million) and an increase in the fixed component of the contract price by that amount, and (b) a credit to SCE&G and Santee Cooper of $50 million (SCE&G’s 55% portion being approximately $27 million) to be applied to the target component of the contract price, (ii) revise the guaranteed substantial completion dates of Units 2 and 3 to August 31, 2019 and 2020, respectively, (iii) revise the delay-related liquidated damages computation requirements, including those related to the eligibility of the New Units to earn Internal Revenue Code Section 45J production tax credits (see also below), and cap those aggregate liquidated damages at $463 million per New Unit (SCE&G’s 55% portion being approximately $255 million per New Unit), (iv) provide for payment to the Consortium of a completion bonus of $275 million per New Unit (SCE&G’s 55% portion being approximately $151 million per New Unit) for each New Unit placed in service by the deadline to qualify for production tax credits, (v) provide for the development of a revised construction milestone payment schedule, with SCE&G and Santee Cooper making monthly payments of $100 million (SCE&G’s 55% portion being $55 million) for each of the first five months following effectiveness, followed by payments made based on milestones achieved, and (vi) provide that SCE&G and Santee Cooper waive and cancel the CB&I parent company guaranty with respect to the project. The payment obligations under the EPC Contract are joint and several obligations of WEC and Stone & Webster, and the October 2015 Amendment provides for Toshiba Corporation, WEC’s parent company, to reaffirm its guaranty of WEC’s payment obligations. Under the October 2015 Amendment, SCE&G’s total estimated project costs will increase by approximately $286 million over the $6.8 billion approved by the SCPSC in September 2015, and will bring its total estimated gross construction cost of the project (including escalation and AFC) to approximately $7.1 billion.

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

Finally, upon effectiveness, the October 2015 Amendment would provide SCE&G and Santee Cooper an irrevocable option, until November 1, 2016 and subject to regulatory approvals, to further amend the EPC Contract to fix the total amount to be paid to the Consortium for its entire scope of work on the project (excluding a limited amount of work within the time and materials component of the contract price) after June 30, 2015 at $6.082 billion (SCE&G’s 55% portion being approximately $3.345 billion). This total amount to be paid would be subject to adjustment for amounts paid since June 30, 2015. Were this fixed price option to be exercised, the aggregate delay-related liquidated damages amount referred to in (iii) above would be capped at $338 million per unit (SCE&G’s 55% portion being approximately $186 million per unit), and the completion bonus amounts referred to in (iv) above would be $150 million per New Unit (SCE&G’s 55% portion being approximately $83 million per New Unit). The exercise of this fixed price option would result in SCE&G’s total estimated project costs increasing by approximately $774 million over the $6.8 billion approved by the SCPSC in September 2015, and would bring its total estimated gross construction cost (including escalation and AFC) of the project to approximately $7.6 billion.

Resolution of the disputes as described in (i) above, or in the case of the exercise of the fixed price option, would result in estimated project costs above the amounts approved by the SCPSC; however, the guaranteed substantial completion dates fall within the SCPSC approved 18-month contingency periods. SCE&G expects to hold an allowable ex parte communication briefing with the SCPSC on November 19, 2015 and, following an evaluation as to whether to exercise the fixed price option, expects to file a petition, as provided under the BLRA, for an update to the project’s estimated capital cost schedule which would incorporate the impact of this October 2015 Amendment.

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

Santee Cooper Matters

As noted above, SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper. Under the terms of this agreement, SCE&G will acquire a 1% ownership interest in the New Units at the commercial operation date of Unit 2, an additional 2% ownership interest no later than the first anniversary of such commercial operation date, and the final 2% no later than the second anniversary of such commercial operation date. SCE&G has agreed to pay an amount equal to Santee Cooper's actual cost, including its cost of financing, of the percentage conveyed as of the date of each conveyance. In addition, the agreement provides that Santee Cooper will not transfer any of its remaining interest in the New Units to third parties until the New Units are complete. This transaction will not affect the payment obligations between the parties during construction for the New Units, nor is it anticipated that the payments for the additional ownership interest would be reflected in a revised rates filing under the BLRA. Based on the current milestone schedule and capital costs schedule approved by the SCPSC in September 2015 and without considering the October 2015 Amendment discussed above, SCE&G’s estimated cost would be approximately $750 million for the additional 5% interest being acquired from Santee Cooper.

Nuclear Production Tax Credits

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

Other Project Matters

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

Environmental

The Company's operations are subject to extensive regulation by various federal and state authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes. Applicable statutes and rules include the CAA, CWA, Nuclear Waste Act and CERCLA, among others. In many cases, regulations proposed by such authorities could have a significant impact on the Company's financial condition, results of operations and cash flows. In addition, the Company often cannot predict what conditions or requirements will be imposed by regulatory or legislative proposals. To the extent that compliance with environmental regulations or legislation results in capital expenditures or operating costs, the Company expects to recover such expenditures and costs through existing ratemaking provisions.

From a regulatory perspective, SCANA, SCE&G and GENCO continually monitor and evaluate their current and projected emission levels and strive to comply with all state and federal regulations regarding those emissions. SCE&G and GENCO participate in the sulfur dioxide and nitrogen oxide emission allowance programs with respect to coal plant emissions and also have constructed additional pollution control equipment at several larger coal-fired electric generating plants. Further, SCE&G is engaged in construction activities of the New Units which are expected to reduce GHG emission levels significantly once they are completed and dispatched by potentially displacing some of the current coal-fired generation sources. These actions are expected to address many of the rules and regulations discussed herein.

On August 3, 2015, the EPA issued a revised carbon standard for new power plants by re-proposing NSPS under the CAA for emissions of carbon dioxide from newly constructed fossil fuel-fired units. The final rule requires all new coal-fired power plants to meet a carbon emission rate of 1,400 pounds carbon dioxide per MWh and new natural gas units to meet 1,000 pounds carbon dioxide per MWh. While most new natural gas plants will not be required to include any new technologies, no new coal-fired plants could be constructed without partial carbon capture and sequestration capabilities. The Company is evaluating the final rule, but does not plan to construct new coal-fired units in the foreseeable future. In addition, on August 3, 2015, the EPA issued its final rule on emission guidelines for states to follow in developing plans to address GHG emissions from existing units. The rule includes state-specific goals for reducing national carbon dioxide emissions by 32% from 2005 levels by 2030. The rule also provides for nuclear reactors under construction, such as the New Units, to count towards compliance and establishes a phased-in compliance approach beginning in 2022. The Company is currently evaluating the rule and expects any costs incurred to comply with such rule to be recoverable through rates.

In July 2011, the EPA issued the CSAPR to reduce emissions of sulfur dioxide and nitrogen oxide from power plants in the eastern half of the United States. A series of court actions stayed this rule until October 23, 2014, when the Court of Appeals granted a motion to lift the stay. On December 3, 2014, the EPA published an interim final rule that aligns the dates in the CSAPR text with the revised court-ordered schedule, thus delaying the implementation dates to 2015 for Phase 1 and to 2017 for Phase 2. The CSAPR replaces the CAIR and requires a total of 28 states to reduce annual sulfur dioxide emissions and annual or ozone season nitrogen oxide emissions to assist in attaining the ozone and fine particle NAAQS. The rule establishes an emissions cap for sulfur dioxide and nitrogen oxide and limits the trading for emission allowances by separating affected states into two groups with no trading between the groups. On July 28, 2015, the Court of Appeals held that Phase 2 emissions budgets for certain states, including South Carolina, required reductions in emissions beyond the point necessary to achieve downwind attainment and were, therefore, invalid. The Court of Appeals remanded CSAPR, without vacating the rule, to the EPA for further consideration. The opinion of the Court of Appeals has no immediate impact on SCE&G and GENCO or their generation operations. Air quality control installations that SCE&G and GENCO have already completed have positioned them to comply with the existing allowances set by the CSAPR. Any cost incurred to comply with CSAPR are expected to be recoverable through rates.

In April 2012, the EPA's MATS rule containing new standards for mercury and other specified air pollutants became effective. The rule provides up to four years for generating facilities to meet the standards, and the Company's evaluation of the rule is ongoing. The Company's decision to retire certain coal-fired units (see Note 2) and its project to build the New Units along with other actions are expected to result in the Company's compliance with MATS.

On November 19, 2014, the EPA finalized its reconsideration of certain provisions applicable during startup and shutdown of generating facilities. SCE&G and GENCO have received a one year extension (until April 2016) to comply with MATS at Cope, McMeekin, Wateree and Williams Stations. These extensions will allow time to convert McMeekin Station to burn natural gas and to install additional pollution control devices at the other plants that will enhance the control of certain MATS-regulated pollutants. On June 29, 2015, the U.S. Supreme Court ruled that the EPA unreasonably failed to consider costs in its decision to regulate, and remanded a case challenging the regulation on that basis to the Court of Appeals. The ruling, however, is not expected to have an impact on SCE&G or GENCO due to the aforementioned retirements and conversions.

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

The CWA Section 316(b) Existing Facilities Rule became effective in October 2014. This rule establishes national requirements for the location, design, construction and capacity of cooling water intake structures at existing facilities that reflect the best technology available for minimizing the adverse environmental impacts of impingement and entrainment. SCE&G and GENCO are conducting studies and implementing plans to ensure compliance with this rule. In addition, Congress is expected to consider further amendments to the CWA. Such legislation may include toxicity-based standards as well as limitations to mixing zones.

On April 17, 2015, the EPA's final rule for CCR was published in the Federal Register and became effective in the fourth quarter of 2015. This rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act and imposes certain requirements on ash storage ponds and other CCR management facilities at SCE&G's and GENCO's coal-fired generating facilities. Although the full effects of this rule are still being evaluated, SCE&G and GENCO have already closed or have begun the process of closure of all of their ash storage ponds and have previously recognized AROs for such ash storage ponds under existing requirements. The Company does not expect the incremental compliance costs associated with this rule to be significant and expects to recover such costs in future rates.

The Nuclear Waste Act required that the United States government accept and permanently dispose of high-level radioactive waste and spent nuclear fuel by January 31, 1998, and it imposed on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. SCE&G entered into a Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with the DOE in 1983. As of September 30, 2015, the federal government has not accepted any spent fuel from Summer Station Unit 1, and it remains unclear when the repository may become available. SCE&G has on-site spent nuclear fuel storage capability in its existing fuel pool until at least 2017 and is constructing a dry cask storage facility to accommodate the spent nuclear fuel output for the life of Summer Station Unit 1. SCE&G may evaluate other technology as it becomes available.

The provisions of CERCLA authorize the EPA to require the clean-up of hazardous waste sites. The states of South Carolina and North Carolina have similar laws. The Company maintains an environmental assessment program to identify and evaluate current and former operations sites that could require clean-up. In addition, regulators from the EPA and other federal or state agencies periodically notify the Company that it may be required to perform or participate in the investigation and remediation of a hazardous waste site. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures may differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Such amounts are recorded in regulatory assets and amortized, with recovery provided through rates.

SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC and the EPA. SCE&G anticipates that major remediation activities at all these sites will continue at least through 2017 and will cost an additional $19.0 million, which is accrued in Other within Deferred Credits and Other Liabilities on the condensed consolidated balance sheet. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates. At September 30, 2015, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $34.7 million and are included in regulatory assets.

Asset Retirement Obligations

The Company recognizes a liability for the present value of an ARO when incurred if the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional ARO is factored into the measurement of the liability when sufficient information exists, but such uncertainty is not a basis upon which to avoid liability recognition.

The legal obligations associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation relate primarily to the Company’s utility operations.  As of September 30, 2015 and December 31, 2014, the Company has recorded AROs of approximately $174 million and $201 million, respectively, for nuclear plant decommissioning and AROs of approximately $315 million and $362 million, respectively, for other conditional obligations primarily related to generation, transmission and distribution properties, including gas pipelines. All of the amounts recorded are based upon estimates which are subject to varying degrees of imprecision, particularly since such payments will be made many years in the future.

A reconciliation of the beginning and ending carrying amount of asset retirement obligations is as follows:

Millions of dollars	September 30, 2015			December 31, 2014
Beginning balance	$	563		$	576
Liabilities incurred	—			3
Liabilities settled	(15		)	(6		)
Accretion expense	20			26
Revisions in estimated cash flows	(79		)	(36		)
Ending balance	$	489		$	563

Revisions in estimated cash flows during 2015 primarily relate to changes in the expected timing of settlement of AROs in light of changes in the estimated useful lives of certain electric utility properties identified as part of a customary depreciation study.

SCEG

Statement [Line Items]

Commitments and Contingencies Disclosure [Text Block]

COMMITMENTS AND CONTINGENCIES

 Nuclear Insurance

Under Price-Anderson, SCE&G (for itself and on behalf of Santee Cooper, a one-third owner of Summer Station Unit 1) maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at SCE&G's nuclear power plant. Price-Anderson provides funds up to $12.9 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $375 million by ANI with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. Each reactor licensee is currently liable for up to $127.3 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $18.9 million of the liability per reactor would be assessed per year.  SCE&G’s maximum assessment, based on its two-thirds ownership of Summer Station Unit 1, would be $84.8 million per incident, but not more than $12.6 million per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years.

SCE&G currently maintains insurance policies (for itself and on behalf of Santee Cooper) with NEIL.  The policies provide coverage to Summer Station Unit 1 for property damage and outage costs up to $2.75 billion resulting from an event of nuclear origin. In addition, a builder's risk insurance policy has been purchased from NEIL for the construction of the New Units. This policy provides the owners of the New Units up to $500 million in limits of accidental property damage occurring during construction. The NEIL policies, in the aggregate, are subject to a maximum loss of $2.75 billion for any single loss occurrence. All of the NEIL policies permit retrospective assessments under certain conditions to cover insurer’s losses.  Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $45.9 million.

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

New Nuclear Construction

In 2008, SCE&G, on behalf of itself and as agent for Santee Cooper, contracted with the Consortium for the design and construction of the New Units at the site of Summer Station.  

SCE&G's current ownership share in the New Units is 55%. As discussed below, under an agreement signed in January 2014 (and subject to customary closing conditions, including necessary regulatory approvals), SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper.

EPC Contract and BLRA Matters

The construction of the New Units and SCE&G’s related recovery of financing costs through rates is subject to review and approval by the SCPSC as provided for in the BLRA. Under the BLRA, the SCPSC has approved, among other things, a milestone schedule and a capital costs estimates schedule for the New Units. This approval constitutes a final and binding determination that the New Units are used and useful for utility purposes, and that the capital costs associated with the New Units are prudent utility costs and expenses and are properly included in rates, so long as the New Units are constructed or are being constructed within the parameters of the approved milestone schedule, including specified schedule contingencies, and the approved capital costs estimates schedule. Subject to the same conditions, the BLRA provides that SCE&G may apply to the SCPSC annually for an order to recover through revised rates SCE&G’s weighted average cost of capital applied to all or part of the outstanding balance of construction work in progress concerning the New Units. Such annual rate changes are described in Note 2. As of September 30, 2015, SCE&G’s investment in the New Units, including related transmission, totaled $3.3 billion, for which the financing costs on $2.4 billion have been reflected in rates under the BLRA.

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

Since the settlement of delay-related claims in 2012, the Consortium has continued to experience delays in the schedule, including those related to fabrication and delivery of sub-modules for the New Units. The fabrication and delivery of sub-modules have been and remain focus areas of the Consortium. Shield building panels are considered critical path items for both New Units, and the current schedule for production of such panels will require mitigation to support the updated substantial completion dates (see below).

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

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

In September 2015, the SCPSC approved an updated BLRA milestone schedule based on revised substantial completion dates for Units 2 and 3 of June 2019 and June 2020, respectively, each subject to an 18-month contingency period. In addition, the SCPSC approved certain updated owner's costs ($245 million) and other capital costs ($453 million), of which $539 million were associated with the schedule delays and other contested costs. SCE&G's total projected capital costs (in 2007 dollars) and gross construction cost estimates (including escalation and AFC) were estimated to be $5.2 billion and $6.8 billion, respectively. These projections included cost amounts related to the Revised, Fully-Integrated Construction Schedule for which SCE&G had not accepted responsibility and which were the subject of dispute. As such, these updated milestone schedule and projections did not reflect the resolution of negotiations. In addition, the SCPSC approved a revision to the allowed return on equity for new nuclear construction from 11.00% to 10.50%. This revised return on equity will be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2016, until such time as the New Units are completed.

On October 27, 2015, SCE&G, Santee Cooper and the Consortium reached a settlement regarding the above mentioned disputes, and the EPC Contract was amended. The October 2015 Amendment will become effective upon the consummation of the acquisition by WEC of the stock of Stone & Webster from CB&I, and will become null and void in the event such acquisition is not consummated by March 31, 2016. Following that acquisition, Stone & Webster will continue to be a member of the Consortium as a subsidiary of WEC rather than CB&I, and WEC intends to engage Fluor Corporation or its affiliate(s) as a subcontracted construction manager.

Among other things, upon effectiveness, the October 2015 Amendment would (i) resolve by settlement and release substantially all outstanding disputes between SCE&G and the Consortium, in exchange for (a) an additional cost to be paid by SCE&G and Santee Cooper of $300 million (SCE&G’s 55% portion being $165 million) and an increase in the fixed component of the contract price by that amount, and (b) a credit to SCE&G and Santee Cooper of $50 million (SCE&G’s 55% portion being approximately $27 million) to be applied to the target component of the contract price, (ii) revise the guaranteed substantial completion dates of Units 2 and 3 to August 31, 2019 and 2020, respectively, (iii) revise the delay-related liquidated damages computation requirements, including those related to the eligibility of the New Units to earn Internal Revenue Code Section 45J production tax credits (see also below), and cap those aggregate liquidated damages at $463 million per New Unit (SCE&G’s 55% portion being approximately $255 million per New Unit), (iv) provide for payment to the Consortium of a completion bonus of $275 million per New Unit (SCE&G’s 55% portion being approximately $151 million per New Unit) for each New Unit placed in service by the deadline to qualify for production tax credits, (v) provide for the development of a revised construction milestone payment schedule, with SCE&G and Santee Cooper making monthly payments of $100 million (SCE&G’s 55% portion being $55 million) for each of the first five months following effectiveness, followed by payments made based on milestones achieved, and (vi) provide that SCE&G and Santee Cooper waive and cancel the CB&I parent company guaranty with respect to the project. The payment obligations under the EPC Contract are joint and several obligations of WEC and Stone & Webster, and the October 2015 Amendment provides for Toshiba Corporation, WEC’s parent company, to reaffirm its guaranty of WEC’s payment obligations. Under the October 2015 Amendment, SCE&G’s total estimated project costs will increase by approximately $286 million over the $6.8 billion approved by the SCPSC in September 2015, and will bring its total estimated gross construction cost of the project (including escalation and AFC) to approximately $7.1 billion.

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

Finally, upon effectiveness, the October 2015 Amendment would provide SCE&G and Santee Cooper an irrevocable option, until November 1, 2016 and subject to regulatory approvals, to further amend the EPC Contract to fix the total amount to be paid to the Consortium for its entire scope of work on the project (excluding a limited amount of work within the time and materials component of the contract price) after June 30, 2015 at $6.082 billion (SCE&G’s 55% portion being approximately $3.345 billion). This total amount to be paid would be subject to adjustment for amounts paid since June 30, 2015. Were this fixed price option to be exercised, the aggregate delay-related liquidated damages amount referred to in (iii) above would be capped at $338 million per unit (SCE&G’s 55% portion being approximately $186 million per unit), and the completion bonus amounts referred to in (iv) above would be $150 million per New Unit (SCE&G’s 55% portion being approximately $83 million per New Unit). The exercise of this fixed price option would result in SCE&G’s total estimated project costs increasing by approximately $774 million over the $6.8 billion approved by the SCPSC in September 2015, and would bring its total estimated gross construction cost (including escalation and AFC) of the project to approximately $7.6 billion.

Resolution of the disputes as described in (i) above, or in the case of the exercise of the fixed price option, would result in estimated project costs above the amounts approved by the SCPSC; however, the guaranteed substantial completion dates fall within the SCPSC approved 18-month contingency periods. SCE&G expects to hold an allowable ex parte communication briefing with the SCPSC on November 19, 2015 and, following an evaluation as to whether to exercise the fixed price option, expects to file a petition, as provided under the BLRA, for an update to the project’s estimated capital cost schedule which would incorporate the impact of this October 2015 Amendment.

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

Santee Cooper Matters

As noted above, SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper. Under the terms of this agreement, SCE&G will acquire a 1% ownership interest in the New Units at the commercial operation date of Unit 2, an additional 2% ownership interest no later than the first anniversary of such commercial operation date, and the final 2% no later than the second anniversary of such commercial operation date. SCE&G has agreed to pay an amount equal to Santee Cooper's actual cost, including its cost of financing, of the percentage conveyed as of the date of each conveyance. In addition, the agreement provides that Santee Cooper will not transfer any of its remaining interest in the New Units to third parties until the New Units are complete. This transaction will not affect the payment obligations between the parties during construction for the New Units, nor is it anticipated that the payments for the additional ownership interest would be reflected in a revised rates filing under the BLRA. Based on the current milestone schedule and capital costs schedule approved by the SCPSC in September 2015 and without considering the October 2015 Amendment discussed above, SCE&G’s estimated cost would be approximately $750 million for the additional 5% interest being acquired from Santee Cooper.

Nuclear Production Tax Credits

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

Other Project Matters

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

Environmental

Consolidated SCE&G's operations are subject to extensive regulation by various federal and state authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes. Applicable statutes and rules include the CAA, CWA, Nuclear Waste Act and CERCLA, among others. In many cases, regulations proposed by such authorities could have a significant impact on Consolidated SCE&G's financial condition, results of operations and cash flows. In addition, Consolidated SCE&G often cannot predict what conditions or requirements will be imposed by regulatory or legislative proposals. To the extent that compliance with environmental regulations or legislation results in capital expenditures or operating costs, Consolidated SCE&G expects to recover such expenditures and costs through existing ratemaking provisions.

From a regulatory perspective, SCE&G and GENCO continually monitor and evaluate their current and projected emission levels and strive to comply with all state and federal regulations regarding those emissions. SCE&G and GENCO participate in the sulfur dioxide and nitrogen oxide emission allowance programs with respect to coal plant emissions and also have constructed additional pollution control equipment at several larger coal-fired electric generating plants. Further, SCE&G is engaged in construction activities of the New Units which are expected to reduce GHG emission levels significantly once they are completed and dispatched by potentially displacing some of the current coal-fired generation sources. These actions are expected to address many of the rules and regulations discussed herein.

On August 3, 2015, the EPA issued a revised carbon standard for new power plants by re-proposing NSPS under the CAA for emissions of carbon dioxide from newly constructed fossil fuel-fired units. The final rule requires all new coal-fired power plants to meet a carbon emission rate of 1,400 pounds carbon dioxide per MWh and new natural gas units to meet 1,000 pounds carbon dioxide per MWh. While most new natural gas plants will not be required to include any new technologies, no new coal-fired plants could be constructed without partial carbon capture and sequestration capabilities. SCE&G and GENCO are evaluating the final rule, but do not plan to construct new coal-fired units in the foreseeable future. In addition, on August 3, 2015, the EPA issued its final rule on emission guidelines for states to follow in developing plans to address GHG emissions from existing units. The rule includes state-specific goals for reducing national carbon dioxide emissions by 32% from 2005 levels by 2030. The rule also provides for nuclear reactors under construction, such as the New Units, to count towards compliance and establishes a phased-in compliance approach beginning in 2022. Consolidated SCE&G is currently evaluating the rule and expects any costs incurred to comply with such rule to be recoverable through rates.

In July 2011, the EPA issued the CSAPR to reduce emissions of sulfur dioxide and nitrogen oxide from power plants in the eastern half of the United States. A series of court actions stayed this rule until October 23, 2014, when the Court of Appeals granted a motion to lift the stay. On December 3, 2014, the EPA published an interim final rule that aligns the dates in the CSAPR text with the revised court-ordered schedule, thus delaying the implementation dates to 2015 for Phase 1 and to 2017 for Phase 2. The CSAPR replaces the CAIR and requires a total of 28 states to reduce annual sulfur dioxide emissions and annual or ozone season nitrogen oxide emissions to assist in attaining the ozone and fine particle NAAQS. The rule establishes an emissions cap for sulfur dioxide and nitrogen oxide and limits the trading for emission allowances by separating affected states into two groups with no trading between the groups. On July 28, 2015, the Court of Appeals held that Phase 2 emissions budgets for certain states, including South Carolina, required reductions in emissions beyond the point necessary to achieve downwind attainment and were, therefore, invalid. The Court of Appeals remanded CSAPR, without vacating the rule, to the EPA for further consideration. The opinion of the Court of Appeals has no immediate impact on SCE&G and GENCO or their generation operations. Air quality control installations that SCE&G and GENCO have already completed have positioned them to comply with the existing allowances set by the CSAPR. Any cost incurred to comply with CSAPR are expected to be recoverable through rates.

In April 2012, the EPA's MATS rule containing new standards for mercury and other specified air pollutants became effective.  The rule provides up to four years for generating facilities to meet the standards, and SCE&G and GENCO's evaluation of the rule is ongoing. SCE&G's decision to retire certain coal-fired units (see Note 2) and its project to build the New Units along with other actions are expected to result in SCE&G's compliance with MATS.

On November 19, 2014, the EPA finalized its reconsideration of certain provisions applicable during startup and shutdown of generating facilities. SCE&G and GENCO have received a one year extension (until April 2016) to comply with MATS at Cope, McMeekin, Wateree and Williams Stations. These extensions will allow time to convert McMeekin Station to burn natural gas and to install additional pollution control devices at the other plants that will enhance the control of certain MATS-regulated pollutants. On June 29, 2015, the U.S. Supreme Court ruled that the EPA unreasonably failed to consider costs in its decision to regulate, and remanded a case challenging the regulation on that basis to the Court of Appeals. The ruling, however, is not expected to have an impact on SCE&G or GENCO due to the aforementioned retirements and conversions.

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

The CWA Section 316(b) Existing Facilities Rule became effective in October 2014. This rule establishes national requirements for the location, design, construction and capacity of cooling water intake structures at existing facilities that reflect the best technology available for minimizing the adverse environmental impacts of impingement and entrainment. SCE&G and GENCO are conducting studies and implementing plans to ensure compliance with this rule. In addition, Congress is expected to consider further amendments to the CWA. Such legislation may include toxicity-based standards as well as limitations to mixing zones.

On April 17, 2015, the EPA's final rule for CCR was published in the Federal Register and became effective in the fourth quarter of 2015. This rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act and imposes certain requirements on ash storage ponds and other CCR management facilities at SCE&G's and GENCO's coal-fired generating facilities. Although the full effects of this rule are still being evaluated, SCE&G and GENCO have already closed or have begun the process of closure of all of their ash storage ponds and have previously recognized AROs for such ash storage ponds under existing requirements. Consolidated SCE&G does not expect the incremental compliance costs associated with this rule to be significant and expects to recover such costs in future rates.

The Nuclear Waste Act required that the United States government accept and permanently dispose of high-level radioactive waste and spent nuclear fuel by January 31, 1998, and it also imposed on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. SCE&G entered into a Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with the DOE in 1983. As of September 30, 2015, the federal government has not accepted any spent fuel from Summer Station Unit 1, and it remains unclear when the repository may become available. SCE&G has on-site spent nuclear fuel storage capability in its existing fuel pool until at least 2017 and is constructing a dry cask storage facility to accommodate the spent nuclear fuel output for the life of Summer Station Unit 1. SCE&G may evaluate other technology as it becomes available.

The provisions of CERCLA authorize the EPA to require the clean-up of hazardous waste sites. The state of South Carolina has similar laws. SCE&G maintains an environmental assessment program to identify and evaluate current and former operations sites that could require clean-up. In addition, regulators from the EPA and other federal or state agencies periodically notify SCE&G that it may be required to perform or participate in the investigation and remediation of a hazardous waste site. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures may differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Such amounts are recorded in regulatory assets and amortized, with recovery provided through rates.

SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals.  These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC and the EPA.  SCE&G anticipates that major remediation activities at all these sites will continue at least through 2017 and will cost an additional $19.0 million, which is accrued in Other within Deferred Credits and Other Liabilities on the condensed consolidated balance sheet.  SCE&G expects to recover any cost arising from the remediation of MGP sites through rates.  At September 30, 2015, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $34.7 million and are included in regulatory assets.

Asset Retirement Obligations

Consolidated SCE&G recognizes a liability for the present value of an ARO when incurred if the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional ARO is factored into the measurement of the liability when sufficient information exists, but such uncertainty is not a basis upon which to avoid liability recognition.

The legal obligations associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation relate primarily to Consolidated SCE&G’s utility operations.  As of September 30, 2015 and December 31, 2014, Consolidated SCE&G has recorded AROs of approximately $174 million and $201 million, respectively, for nuclear plant decommissioning and AROs of approximately $286 million and $335 million, respectively, for other conditional obligations primarily related to generation, transmission and distribution properties, including gas pipelines. All of the amounts recorded are based upon estimates which are subject to varying degrees of imprecision, particularly since such payments will be made many years in the future.

A reconciliation of the beginning and ending carrying amount of asset retirement obligations is as follows:

Millions of dollars	September 30, 2015			December 31, 2014
Beginning balance	$	536		$	547
Liabilities incurred	—			3
Liabilities settled	(15		)	(6		)
Accretion expense	18			25
Revisions in estimated cash flows	(79		)	(33		)
Ending balance	$	460		$	536

Revisions in estimated cash flows during 2015 primarily relate to changes in the expected timing of settlement of AROs in light of changes in the estimated useful lives of certain electric utility properties identified as part of a customary depreciation study.

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

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COMMON EQUITY

9 Months Ended

Sep. 30, 2015

Schedule of Capitalization, Equity [Line Items]

Stockholders' Equity Note Disclosure [Text Block]

COMMON EQUITY

Changes in common equity during the nine months ended September 30, 2015 and 2014 were as follows:

	Common Stock									Accumulated Other Comprehensive Income (Loss)
Millions	Shares	Outstanding Amount		Treasury Shares			Retained Earnings			Gains(Losses) on Cash Flow Hedges			Deferred Employee Benefit Plans			Total AOCI			Total Common Equity
Balance as of January 1, 2015	143	$	2,388	$	(10	)	$	2,684		$	(63	)	$	(12	)	$	(75	)	$	4,987
Net Income							648												648
Other Comprehensive Income (Loss):
Losses during the period										(8		)	(3		)	(11		)	(11		)
Reclassified from AOCI										16			—			16			16
Total Comprehensive Income (Loss)							648			8			(3		)	5			653
Issuance of Common Stock	—	14		(1		)													13
Dividends Declared							(234		)										(234		)
Balance as of September 30, 2015	143	$	2,402	$	(11	)	$	3,098		$	(55	)	$	(15	)	$	(70	)	$	5,419
Balance as of January 1, 2014	141	$	2,289	$	(9	)	$	2,444		$	(52	)	$	(8	)	$	(60	)	$	4,664
Net Income							433												433
Other Comprehensive Income:
Losses during the period										(3		)	—			(3		)	(3		)
Reclassified from AOCI										1			1			2			2
Total Comprehensive Income							433			(2		)	1			(1		)	432
Issuance of Common Stock	1	76		(1		)													75
Dividends Declared							(223		)										(223		)
Balance as of September 30, 2014	142	$	2,365	$	(10	)	$	2,654		$	(54	)	$	(7	)	$	(61	)	$	4,948

Gains and losses on cash flow hedges reclassified during the nine months ended September 30, 2015 resulted in higher interest expense of $6 million and higher cost of gas purchased for resale of $10 million. Such reclassifications during the comparable period in 2014 resulted in higher interest expense of $5 million and lower cost of gas purchased for resale of $4 million.

SCANA had 200 million shares of common stock authorized as of September 30, 2015 and December 31, 2014.

SCEG

Schedule of Capitalization, Equity [Line Items]

Stockholders' Equity Note Disclosure [Text Block]

EQUITY

Changes in common equity during the nine months ended September 30, 2015 and 2014 were as follows:

	Common Stock			Retained			Accumulated Other Comprehensive			Noncontrolling			Total
Millions	Shares	Amount		Earnings			Income (Loss)			Interest			Equity
Balance at January 1, 2015	40	$	2,560	$	2,077		$	(3	)	$	123		$	4,757
Earnings available to common shareholder				394						11			405
Deferred cost of employee benefit plans							—						—
Total Comprehensive Income				394			—			11			405
Capital contributions from parent		196											196
Cash dividend declared				(205		)				(5		)	(210		)
Balance at September 30, 2015	40	$	2,756	$	2,266		$	(3	)	$	129		$	5,148
Balance at January 1, 2014	40	$	2,479	$	1,896		$	(3	)	$	117		$	4,489
Earnings available to common shareholder				374						9			383
Deferred cost of employee benefit plans							—						—
Total Comprehensive Income				374			—			9			383
Capital contributions from parent		82											82
Cash dividend declared				(192		)				(5		)	(197		)
Balance at September 30, 2014	40	$	2,561	$	2,078		$	(3	)	$	121		$	4,757

SCE&G had 50 million shares of common stock authorized as of September 30, 2015 and December 31, 2014. SCE&G had 20 million shares of preferred stock authorized as of September 30, 2015 and December 31, 2014, of which 1,000 shares at a stated value of $100,000 were issued and outstanding during all periods presented. All issued and outstanding shares of SCE&G's common and preferred stock are held by SCANA.

Reclassifications from AOCI into earnings of the amortization of deferred employee benefit costs were not significant for any period presented.

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RATE AND OTHER REGULATORY MATTERS

9 Months Ended

Sep. 30, 2015

Rate Matters [Line Items]

Public Utilities Disclosure [Text Block]

RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric - Cost of Fuel

SCE&G's retail electric rates include a cost of fuel component approved by the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased by SCE&G.

Pursuant to an April 2014 SCPSC order, SCE&G increased its base fuel cost component by approximately $10.3 million for the 12-month period beginning with the first billing cycle of May 2014. The base fuel cost increase was offset by a reduction in SCE&G's rate rider related to pension costs approved by the SCPSC in March 2014. In addition, pursuant to the April 2014 order, electric revenue for 2014 was reduced by approximately $46 million for adjustments to the fuel cost component and related under-collected fuel balance. Such adjustments are fully offset by the recognition within other income of gains realized from the late 2013 settlement of certain interest rate derivatives which had been entered into in anticipation of the issuance of long-term debt, which gains had been deferred as a regulatory liability. The order also provided for the accrual of certain debt-related carrying costs on its under-collected balance of base fuel costs during the period May 1, 2014 through April 30, 2015.

The cost of fuel includes amounts paid by SCE&G pursuant to the Nuclear Waste Act for the disposal of spent nuclear fuel. As a result of a November 2013 decision by the Court of Appeals, the DOE set the Nuclear Waste Act fee to zero effective May 16, 2014. The impact of changes to the Nuclear Waste Act fee is considered during annual fuel rate proceedings.

By order dated April 30, 2015, the SCPSC approved a settlement agreement among SCE&G and certain other parties in which SCE&G agreed to decrease the total fuel cost component of retail electric rates. Under this order, SCE&G is to recover an amount equal to its under-collected balance of base fuel and variable environmental costs as of April 30, 2015, over the subsequent 12-month period beginning with the first billing cycle of May 2015.

By order dated July 15, 2015, the SCPSC approved a settlement agreement among SCE&G and certain other parties concerning SCE&G's petition for approval to participate in a DER program and to recover DER program costs as a separate component of SCE&G's overall fuel factor. Under this order, SCE&G will, among other things, develop renewable energy facilities with a nameplate capacity of at least 84.5 MW by the end of 2020 and have at least 30 MW of utility-scale solar capacity in service by the end of 2016. The order also requires SCE&G to develop incentives for solar energy generated by residential and commercial customers. SCE&G will also make incentives available for residential customers receiving solar power from community solar-programs.

By order dated September 16, 2015, the SCPSC approved SCE&G's request to adopt lower depreciation rates for electric and common plant effective January 1, 2015 resulting in $29 million (or $.12 cents per share) in lower depreciation expense annually. These rates were based on the results of a depreciation study conducted by SCE&G using utility plant balances as of December 31, 2014. In connection with the adoption of the revised depreciation rates, SCE&G recorded lower depreciation expense of approximately $22 million (or $.09 cents per share) in the third quarter of 2015, and pursuant to the SCPSC order, SCE&G reduced its electric operating revenues by approximately $14.5 million (or $.06 cents per share) with an offset to under-collected fuel included within Receivables in the balance sheet. Accordingly, the Company's net income for each of the three and nine months ended September 30, 2015, increased approximately $4.5 million as a result of this change in estimate.

Electric - Base Rates

Pursuant to an SCPSC order, SCE&G removes from rate base deferred income tax assets arising from capital expenditures related to the New Units and accrues carrying costs on those amounts during periods in which they are not included in rate base.  Such carrying costs are determined at SCE&G’s weighted average long-term debt borrowing rate and are recorded as a regulatory asset and other income. Carrying costs during the three and nine months ended September 30, 2015 totaled $2.4 million and $6.5 million, respectively, and during the three and nine months ended September 30, 2014 totaled $1.6 million and $4.1 million, respectively. SCE&G anticipates that when the New Units are placed in service and accelerated tax depreciation is recognized on them, these deferred income tax assets will decline. When these assets are fully offset by related deferred income tax liabilities, the carrying cost accruals will cease, and the regulatory asset will begin to be amortized.

The SCPSC has approved a suite of DSM Programs for development and implementation. SCE&G offers to its retail electric customers several distinct programs designed to assist customers in reducing their demand for electricity and improving their energy efficiency. SCE&G submits annual filings to the SCPSC related to these programs which include actual program costs, net lost revenues (both forecasted and actual), customer incentives, and net program benefits, among other things. As actual DSM Program costs are incurred, they are deferred as regulatory assets (see Regulatory Assets and Regulatory Liabilities below) and recovered through a rate rider approved by the SCPSC. The rate rider also provides for recovery of net lost revenues and for a shared savings incentive. The SCPSC approved the following rate riders pursuant to the annual DSM Programs filings, which went into effect as indicated below:

Year	Effective	Amount
2015	First billing cycle of May	$	32.0	million
2014	First billing cycle of May	$	15.4	million
2013	First billing cycle of May	$	16.9	million

In April 2014, the SCPSC issued an order approving, among other things, SCE&G’s request to utilize approximately $17.8 million of the gains from the late 2013 settlement of certain interest rate derivative instruments, previously deferred as regulatory liabilities, to offset a portion of SCE&G’s DSM Programs rate rider. This order also allowed SCE&G to apply $5.0 million of its storm damage reserve and $5.0 million of the gains from the settlement of certain interest rate derivative instruments to offset previously deferred amounts.

Electric – BLRA

Under the BLRA, SCE&G may file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation. Through 2015, requested rate adjustments have been based on SCE&G's updated cost of debt and capital structure and on an allowed return on common equity of 11.0%. The SCPSC has approved recovery of the following amounts under the BLRA effective for bills rendered on and after October 30 in the following years:

Year	Action			Amount
2015	2.6	%	Increase	$	64.5	million
2014	2.8	%	Increase	$	66.2	million
2013	2.9	%	Increase	$	67.2	million

In September 2015 the SCPSC approved a revision to the allowed return on equity for new nuclear construction from 11.0% to 10.5%. This revised return on equity will be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2016, until such time as the New Units are completed. See Note 9.

Gas - SCE&G

The RSA is designed to reduce the volatility of costs charged to customers by allowing for more timely recovery of the costs that regulated utilities incur related to natural gas infrastructure. The SCPSC has approved the following rate changes pursuant to annual RSA filings effective with the first billing cycle of November in the following years: 

Year	Action			Amount
2015	No change			-
2014	0.6	%	Decrease	$	2.6	million
2013	No change			-

SCE&G's natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred, including transportation costs. SCE&G's gas rates are calculated using a methodology which may adjust the cost of gas monthly based on a 12-month rolling average, and its gas purchasing policies and practices are reviewed annually by the SCPSC. The annual review conducted for the 12-month period ended July 31, 2014 resulted in the SCPSC issuing an order finding that SCE&G's gas purchasing policies and practices during the review period were reasonable and prudent. SCE&G's 2015 annual PGA hearing was held on November 5, 2015 and the SCPSC's decision is pending.

Gas - PSNC Energy

PSNC Energy's Rider D rate mechanism allows it to recover from customers all prudently incurred gas costs and certain related uncollectible expenses as well as losses on negotiated gas and transportation sales.

PSNC Energy establishes rates using a benchmark cost of gas approved by the NCUC, which may be periodically adjusted to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs as necessary to track these changes and accounts for any over- or under-collection of the delivered cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy’s gas purchasing practices annually. In addition, PSNC Energy utilizes a CUT which allows it to adjust its base rates semi-annually for residential and commercial customers based on average per customer consumption.

In October 2015, in connection with PSNC Energy's 2015 Annual Prudence Review, the NCUC determined that PSNC Energy's gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12 months ended March 31, 2015.

In May 2014, the NCUC issued an order requiring utilities to adjust rates to reflect changes in the state corporate income tax rate that had been enacted by the North Carolina legislature and to file a proposal to refund amounts previously collected on a provisional basis. Pursuant to the order, PSNC Energy lowered its rates effective July 1, 2014, and refunded the amounts previously collected through the normal operation of its Rider D rate mechanism. These amounts were not significant for any period presented.

Regulatory Assets and Regulatory Liabilities

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

Millions of dollars	September 30, 2015		December 31, 2014
Regulatory Assets:
Accumulated deferred income taxes	$	284	$	284
Under-collections - electric fuel adjustment clause	—		20
Environmental remediation costs	39		40
AROs and related funding	376		366
Franchise agreements	23		26
Deferred employee benefit plan costs	328		350
Planned major maintenance	—		2
Deferred losses on interest rate derivatives	538		453
Deferred pollution control costs	35		36
Unrecovered plant	128		137
DSM Programs	59		56
Carrying costs on deferred tax assets related to nuclear construction	15		9
Pipeline integrity management costs	16		9
Other	43		35
Total Regulatory Assets	$	1,884	$	1,823

Regulatory Liabilities:
Accumulated deferred income taxes	$	22	$	22
Asset removal costs	729		703
Storm damage reserve	6		6
Deferred gains on interest rate derivatives	87		82
Planned major maintenance	12		—
Other	3		1
Total Regulatory Liabilities	$	859	$	814

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

Under-collections - electric fuel adjustment clause represent amounts due from customers pursuant to the fuel adjustment clause as approved by the SCPSC which are expected to be recovered in retail electric rates over periods exceeding 12 months. 

Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by the Company, and are expected to be recovered over periods of up to approximately 24 years.

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

Franchise agreements represent costs associated with electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. Based on an SCPSC order, SCE&G is recovering these amounts through cost of service rates through approximately 2021.

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

Planned major maintenance related to certain fossil fueled turbine/generation equipment and nuclear refueling outages is accrued in periods other than when incurred, pursuant to specific SCPSC orders. SCE&G collects and accrues $18.4 million annually for fossil fueled turbine/generation equipment maintenance, and collects and accrues $17.2 million annually for nuclear-related refueling charges.

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

Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the scrubbers installed at certain coal-fired generating plants pursuant to specific regulatory orders. Such costs are being recovered through utility rates through 2045.

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

DSM Programs represent deferred costs associated with such programs. As a result of an April 2015 SCPSC order, deferred costs are currently being recovered over approximately five years through an approved rate rider. 

Carrying costs on deferred tax assets related to nuclear construction are calculated on accumulated deferred income tax assets associated with the New Units which are not part of electric rate base using the weighted average long-term debt cost of capital. These carrying costs will be amortized over ten years beginning in approximately 2021.

Pipeline integrity management costs represent costs incurred to comply with regulatory requirements related to certain natural gas pipelines located near moderate to high density populations. Such costs at SCE&G will be amortized at $1.9 million annually beginning in November 2015. Such costs at PSNC Energy will be considered for recovery through rates in its next general rate proceeding.

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

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

The storm damage reserve represents an SCPSC-approved collection through SCE&G electric rates, capped at $100 million, which can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year. Pursuant to specific regulatory orders, SCE&G has suspended storm damage reserve collection through rates indefinitely. During the nine months ended September 30, 2015, no amounts were applied to offset incremental storm damage costs.

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

SCEG

Rate Matters [Line Items]

Public Utilities Disclosure [Text Block]

RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric - Cost of Fuel

SCE&G's retail electric rates include a cost of fuel component approved by the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased.

Pursuant to an April 2014 SCPSC order, SCE&G increased its base fuel cost component by approximately $10.3 million for the 12-month period beginning with the first billing cycle of May 2014. The base fuel cost increase was offset by a reduction in SCE&G's rate rider related to pension costs approved by the SCPSC in March 2014. In addition, pursuant to the April 2014 order, electric revenue for 2014 was reduced by approximately $46 million for adjustments to the fuel cost component and related under-collected fuel balance. Such adjustments are fully offset by the recognition within other income of gains realized from the late 2013 settlement of certain interest rate derivatives which had been entered into in anticipation of the issuance of long-term debt, which gains had been deferred as a regulatory liability. The order also provided for the accrual of certain debt-related carrying costs on its under-collected balance of base fuel costs during the period May 1, 2014 through April 30, 2015.

The cost of fuel includes amounts paid by SCE&G pursuant to the Nuclear Waste Act for the disposal of spent nuclear fuel. As a result of a November 2013 decision by the Court of Appeals, the DOE set the Nuclear Waste Act fee to zero effective May 16, 2014. The impact of changes to the Nuclear Waste Act fee is considered during annual fuel rate proceedings.

By order dated April 30, 2015, the SCPSC approved a settlement agreement among SCE&G and certain other parties in which SCE&G agreed to decrease the total fuel cost component of its retail electric rates. Under this order, SCE&G is to recover an amount equal to its under-collected balance of base fuel and variable environmental costs as of April 30, 2015, over the subsequent 12-month period beginning with the first billing cycle of May 2015.

By order dated July 15, 2015, the SCPSC approved a settlement agreement among SCE&G and certain other parties concerning SCE&G's petition for approval to participate in a DER program and to recover DER program costs as a separate component of SCE&G's overall fuel factor. Under this order, SCE&G will, among other things, develop renewable energy facilities with a nameplate capacity of at least 84.5 MW by the end of 2020 and have at least 30 MW of utility-scale solar capacity in service by the end of 2016. The order also requires SCE&G to develop incentives for solar energy generated by residential and commercial customers. SCE&G will also make incentives available for residential customers receiving solar power from community solar-programs.

By order dated September 16, 2015, the SCPSC approved SCE&G's request to adopt lower depreciation rates for electric and common plant effective January 1, 2015 resulting in $29 million in lower depreciation expense annually. These rates were based on the results of a depreciation study conducted by SCE&G using utility plant balances as of December 31, 2014. In connection with the adoption of the revised depreciation rates, SCE&G recorded lower depreciation expense of approximately $22 million in the third quarter of 2015, and pursuant to the SCPSC order, SCE&G reduced its electric operating revenues by approximately $14.5 million with an offset to under-collected fuel included within Receivables in the balance sheet. Accordingly, Consolidated SCE&G's net income for each of the three and nine months ended September 30, 2015, increased approximately $4.5 million as a result of this change in estimate.

Electric - Base Rates

Pursuant to an SCPSC order, SCE&G removes from rate base deferred income tax assets arising from capital expenditures related to the New Units and accrues carrying costs on those amounts during periods in which they are not included in rate base.  Such carrying costs are determined at SCE&G’s weighted average long-term debt borrowing rate and are recorded as a regulatory asset and other income. Carrying costs during the three and nine months ended September 30, 2015 totaled $2.4 million and $6.5 million, respectively, and during the three and nine months ended September 30, 2014 totaled $1.6 million and $4.1 million, respectively. SCE&G anticipates that when the New Units are placed in service and accelerated tax depreciation is recognized on them, these deferred income tax assets will decline. When these assets are fully offset by related deferred income tax liabilities, the carrying cost accruals will cease, and the regulatory asset will begin to be amortized.

The SCPSC has approved a suite of DSM Programs for development and implementation. SCE&G offers to its retail electric customers several distinct programs designed to assist customers in reducing their demand for electricity and improving their energy efficiency. SCE&G submits annual filings to the SCPSC related to these programs which include actual program costs, net lost revenues both forecasted and actual), customer incentives, and net program benefits, among other things. As actual DSM Program costs are incurred, they are deferred as regulatory assets (see Regulatory Assets and Regulatory Liabilities below) and recovered through a rate rider approved by the SCPSC. The rate rider also provides for recovery of net lost revenues and for a shared savings incentive. The SCPSC approved the following rate riders pursuant to the annual DSM Programs filings, which went into effect as indicated below:

Year	Effective	Amount
2015	First billing cycle of May	$	32.0	million
2014	First billing cycle of May	$	15.4	million
2013	First billing cycle of May	$	16.9	million

In April 2014, the SCPSC issued an order approving, among other things, SCE&G’s request to utilize approximately $17.8 million of the gains from the late 2013 settlement of certain interest rate derivative instruments, previously deferred as regulatory liabilities, to offset a portion of SCE&G’s DSM Programs rate rider. This order also allowed SCE&G to apply $5.0 million of its storm damage reserve and $5.0 million of the gains from the settlement of certain interest rate derivative instruments to offset previously deferred amounts. 

Electric – BLRA

Under the BLRA, SCE&G may file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation. Through 2015, requested rate adjustments have been based on SCE&G's updated cost of debt and capital structure and on an allowed return on common equity of 11.0%. The SCPSC has approved recovery of the following amounts under the BLRA effective for bills rendered on and after October 30 in the following years:

Year	Action			Amount
2015	2.6	%	Increase	$	64.5	million
2014	2.8	%	Increase	$	66.2	million
2013	2.9	%	Increase	$	67.2	million

In September 2015 the SCPSC approved a revision to the allowed return on equity for new nuclear construction from 11.0% to 10.5%. This revised return on equity will be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2016, until such time as the New Units are completed. See Note 9.

Gas

The RSA is designed to reduce the volatility of costs charged to customers by allowing for more timely recovery of the costs that regulated utilities incur related to natural gas infrastructure.  The SCPSC has approved the following rate changes pursuant to annual RSA filings effective with the first billing cycle of November in the following years: 

Year	Action			Amount
2015	No change			-
2014	0.6	%	Decrease	$	2.6	million
2013	No change			-

SCE&G's natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred, including transportation costs. SCE&G's gas rates are calculated using a methodology which may adjust the cost of gas monthly based on a 12-month rolling average, and its gas purchasing policies and practices are reviewed annually by the SCPSC. The annual review conducted for the 12-month period ended July 31, 2014 resulted in the SCPSC issuing an order finding that SCE&G's gas purchasing policies and practices during the review period were reasonable and prudent. SCE&G's 2015 annual PGA hearing was held on November 5, 2015 and the SCPSC's decision is pending.

Regulatory Assets and Regulatory Liabilities

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

Millions of dollars	September 30, 2015		December 31, 2014
Regulatory Assets:
Accumulated deferred income taxes	$	278	$	278
Under collections – electric fuel adjustment clause	—		20
Environmental remediation costs	35		36
AROs and related funding	356		347
Franchise agreements	23		26
Deferred employee benefit plan costs	296		310
Planned major maintenance	—		2
Deferred losses on interest rate derivatives	538		453
Deferred pollution control costs	35		36
Unrecovered plant	128		137
DSM Programs	59		56
Carrying costs on deferred tax assets related to nuclear construction	15		9
Other	45		35
Total Regulatory Assets	$	1,808	$	1,745

Regulatory Liabilities:
Accumulated deferred income taxes	$	16	$	17
Asset removal costs	520		505
Storm damage reserve	6		6
Deferred gains on interest rate derivatives	87		82
Planned major maintenance	12		—
Total Regulatory Liabilities	$	641	$	610

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

Under-collections - electric fuel adjustment clause represent amounts due from customers pursuant to the fuel adjustment clause as approved by the SCPSC which are expected to be recovered in retail electric rates over periods exceeding 12 months. 

Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by SCE&G and are expected to be recovered over periods of up to approximately 24 years.

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

Franchise agreements represent costs associated with electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. Based on an SCPSC order, SCE&G is recovering these amounts through cost of service rates through approximately 2021.

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

Planned major maintenance related to certain fossil fueled turbine/generation equipment and nuclear refueling outages is accrued in periods other than when incurred, pursuant to specific SCPSC orders.  SCE&G collects and accrues $18.4 million annually for fossil fueled turbine/generation equipment maintenance and collects and accrues $17.2 million annually for nuclear-related refueling charges.

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

Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the scrubbers installed at certain coal-fired generating plants pursuant to specific regulatory orders.  Such costs are being recovered through utility rates through 2045. 

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

DSM Programs represent deferred costs associated with such programs.  As a result of an April 2015 SCPSC order, deferred costs are currently being recovered over approximately five years through an approved rate rider. 

Carrying costs on deferred tax assets related to nuclear construction are calculated on accumulated deferred income tax assets associated with the New Units which are not part of electric rate base using the weighted average long-term debt cost of capital. These carrying costs will be amortized over ten years beginning in approximately 2021.

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

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

The storm damage reserve represents an SCPSC-approved collection through SCE&G electric rates, capped at $100 million, which can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year. Pursuant to specific regulatory orders, SCE&G has suspended storm damage reserve collection through rates indefinitely. During the nine months ended September 30, 2015, no amounts were applied to offset incremental storm damage costs.

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

XML

RATE AND OTHER REGULATORY MATTERS (Tables)

9 Months Ended

Sep. 30, 2015

Regulatory Assets

Demand reduction programs [Table Text Block]

Year	Effective	Amount
2015	First billing cycle of May	$	32.0	million
2014	First billing cycle of May	$	15.4	million
2013	First billing cycle of May	$	16.9	million

Schedule of Changes in Electric Rate BLRA [Table Text Block]

Year	Action			Amount
2015	2.6	%	Increase	$	64.5	million
2014	2.8	%	Increase	$	66.2	million
2013	2.9	%	Increase	$	67.2	million

Schedule of Changes in Gas Rate RSA [Table Text Block]

Year	Action			Amount
2015	No change			-
2014	0.6	%	Decrease	$	2.6	million
2013	No change			-

Schedule of Regulatory Assets [Table Text Block]

.

Millions of dollars	September 30, 2015		December 31, 2014
Regulatory Assets:
Accumulated deferred income taxes	$	284	$	284
Under-collections - electric fuel adjustment clause	—		20
Environmental remediation costs	39		40
AROs and related funding	376		366
Franchise agreements	23		26
Deferred employee benefit plan costs	328		350
Planned major maintenance	—		2
Deferred losses on interest rate derivatives	538		453
Deferred pollution control costs	35		36
Unrecovered plant	128		137
DSM Programs	59		56
Carrying costs on deferred tax assets related to nuclear construction	15		9
Pipeline integrity management costs	16		9
Other	43		35
Total Regulatory Assets	$	1,884	$	1,823

Schedule of Regulatory Liabilities [Table Text Block]

Regulatory Liabilities:
Accumulated deferred income taxes	$	22	$	22
Asset removal costs	729		703
Storm damage reserve	6		6
Deferred gains on interest rate derivatives	87		82
Planned major maintenance	12		—
Other	3		1
Total Regulatory Liabilities	$	859	$	814

SCEG

Regulatory Assets

Demand reduction programs [Table Text Block]

Year	Effective	Amount
2015	First billing cycle of May	$	32.0	million
2014	First billing cycle of May	$	15.4	million
2013	First billing cycle of May	$	16.9	million

Schedule of Changes in Electric Rate BLRA [Table Text Block]

Year	Action			Amount
2015	2.6	%	Increase	$	64.5	million
2014	2.8	%	Increase	$	66.2	million
2013	2.9	%	Increase	$	67.2	million

Schedule of Changes in Gas Rate RSA [Table Text Block]

Year	Action			Amount
2015	No change			-
2014	0.6	%	Decrease	$	2.6	million
2013	No change			-

Schedule of Regulatory Assets [Table Text Block]

Millions of dollars	September 30, 2015		December 31, 2014
Regulatory Assets:
Accumulated deferred income taxes	$	278	$	278
Under collections – electric fuel adjustment clause	—		20
Environmental remediation costs	35		36
AROs and related funding	356		347
Franchise agreements	23		26
Deferred employee benefit plan costs	296		310
Planned major maintenance	—		2
Deferred losses on interest rate derivatives	538		453
Deferred pollution control costs	35		36
Unrecovered plant	128		137
DSM Programs	59		56
Carrying costs on deferred tax assets related to nuclear construction	15		9
Other	45		35
Total Regulatory Assets	$	1,808	$	1,745

Schedule of Regulatory Liabilities [Table Text Block]

Regulatory Liabilities:
Accumulated deferred income taxes	$	16	$	17
Asset removal costs	520		505
Storm damage reserve	6		6
Deferred gains on interest rate derivatives	87		82
Planned major maintenance	12		—
Total Regulatory Liabilities	$	641	$	610

XML

SEGMENT OF BUSINESS INFORMATION

9 Months Ended

Sep. 30, 2015

Segment Reporting Information [Line Items]

Segment Reporting Disclosure [Text Block]

SEGMENT OF BUSINESS INFORMATION

The Company’s reportable segments are listed in the following table. The Company uses operating income to measure profitability for its regulated operations; therefore, net income is not allocated to the Electric Operations and Gas Distribution segments. The Company uses net income to measure profitability for its Retail Gas Marketing and Energy Marketing segments.  Gas Distribution is comprised of the local distribution operations of SCE&G and PSNC Energy which meet the criteria for aggregation. All Other includes the parent company, a services company and other nonreportable segments that were insignificant for all periods presented. In addition, All Other includes gains from the sales of CGT and SCI (see Note 11) and their operating results and assets prior to their sale in the first quarter of 2015. CGT and SCI were nonreportable segments during all periods presented. For the period ended September 30, 2015, operating income and net income for All Other include $235 million and $201 million, respectively, related to the sales of CGT and SCI. External revenue and intersegment revenue for All Other related to CGT and SCI were not significant during any period presented.

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

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

Three Months Ended September 30, 2014
Electric Operations	$	739		$	1		$	275		n/a
Gas Distribution	127			—			(6		)	n/a
Retail Gas Marketing	68			—			n/a			$	(3	)
Energy Marketing	182			47			n/a			(2		)
All Other	9			103			7			(5		)
Adjustments/Eliminations	(4		)	(151		)	(7		)	154
Consolidated Total	$	1,121		$	—		$	269		$	144

Nine Months Ended September 30, 2014
Electric Operations	$	2,027		$	5		$	616	n/a
Gas Distribution	728			—			98		n/a
Retail Gas Marketing	367			—			n/a		$	16
Energy Marketing	602			154			n/a		5
All Other	27			317			21		(3		)
Adjustments/Eliminations	(15		)	(476		)	37		415
Consolidated Total	$	3,736		$	—		$	772	$	433

	September 30,		December 31,
Segment Assets	2015		2014
Electric Operations	$	10,531	$	10,182
Gas Distribution	2,498		2,487
Retail Gas Marketing	107		140
Energy Marketing	102		150
All Other	998		1,474
Adjustments/Eliminations	2,270		2,419
Consolidated Total	$	16,506	$	16,852

SCEG

Segment Reporting Information [Line Items]

Segment Reporting Disclosure [Text Block]

SEGMENT OF BUSINESS INFORMATION

Consolidated SCE&G’s reportable segments are listed in the following table.  Consolidated SCE&G uses operating income to measure profitability for its regulated operations.  Therefore, earnings available to common shareholder are not allocated to the Electric Operations and Gas Distribution segments.  Intersegment revenues were not significant.

Millions of dollars	External Revenue		Operating Income			Earnings Available to Common Shareholder
Three Months Ended September 30, 2015
Electric Operations	$	743	$	313		n/a
Gas Distribution	63		(6		)	n/a
Adjustments/Eliminations	—		—			$	164
Consolidated Total	$	806	$	307		$	164

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

Three Months Ended September 30, 2014
Electric Operations	$	740	$	274		n/a
Gas Distribution	72		(2		)	n/a
Adjustments/Eliminations	—		—			$	154
Consolidated Total	$	812	$	272		$	154

Nine Months Ended September 30, 2014
Electric Operations	$	2,032	$	616	n/a
Gas Distribution	337		40		n/a
Adjustments/Eliminations	—		—		$	374
Consolidated Total	$	2,369	$	656	$	374

Segment Assets	September 30, 2015		December 31, 2014
Electric Operations	$	10,531	$	10,182
Gas Distribution	749		721
Adjustments/Eliminations	3,032		3,204
Consolidated Total	$	14,312	$	14,107

XML

DERIVATIVE FINANCIAL INSTRUMENTS

9 Months Ended

Sep. 30, 2015

Derivative [Line Items]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

DERIVATIVE FINANCIAL INSTRUMENTS

The Company recognizes all derivative instruments as either assets or liabilities in the statement of financial position and measures those instruments at fair value. The Company recognizes changes in the fair value of derivative instruments either in earnings, as a component of OCI or, for regulated subsidiaries, within regulatory assets or regulatory liabilities, depending upon the intended use of the derivative and the resulting designation. 

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

Commodity Derivatives

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

PSNC Energy hedges natural gas purchasing activities using over-the-counter options and NYMEX futures and options.  PSNC Energy’s tariffs include a provision for the recovery of actual gas costs incurred, including any costs of hedging.  PSNC Energy records premiums, transaction fees, margin requirements and any realized gains or losses from its hedging program in deferred accounts as a regulatory asset or liability for the under- or over-recovery of gas costs.  These derivative financial instruments are not designated as hedges for accounting purposes.

Unrealized gains and losses on qualifying cash flow hedges of nonregulated operations are deferred in AOCI.  When the hedged transactions affect earnings, previously recorded gains and losses are reclassified from AOCI to cost of gas.  The effects of gains or losses resulting from these hedging activities are either offset by the recording of the related hedged transactions or are included in gas sales pricing decisions made by the business unit.

As an accommodation to certain customers, SEMI, as part of its energy management services, offers fixed price supply contracts which are accounted for as derivatives.  These sales contracts are offset by the purchase of supply futures and swaps which are also accounted for as derivatives. Neither the sales contracts nor the related supply futures and swaps are designated as hedges for accounting purposes.

Interest Rate Swaps

The Company may use interest rate swaps to manage interest rate risk and exposure to changes in fair value attributable to changes in interest rates on certain debt issuances.  The Company synthetically converts variable rate debt to fixed rate debt using swaps that are designated as cash flow hedges. Periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense.

In anticipation of the issuance of debt, the Company may use treasury rate locks or forward starting swap agreements that are designated as cash flow hedges. For GENCO, the effective portions of changes in fair value and payments made or received upon termination of such agreements are recorded in regulatory assets or regulatory liabilities. For the holding company or nonregulated subsidiaries, such amounts are recorded in AOCI. Such amounts are amortized to interest expense over the term of the underlying debt. Ineffective portions of fair value changes are recognized in income.

Pursuant to regulatory orders, interest rate derivatives entered into by SCE&G after October 2013 are not designated as cash flow hedges, and all related fair value changes and settlement amounts are recorded as regulatory assets or liabilities. Interest rate derivatives entered into before October 2013 were designated as cash flow hedges, and for such instruments only the effective portion of fair value changes and settlement amounts are recorded in regulatory assets or regulatory liabilities. Upon settlement, losses on swaps are amortized over the lives of related debt issuances, and gains are applied to under-collected fuel, are amortized to interest expense or are applied as otherwise directed by the SCPSC.

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

Quantitative Disclosures Related to Derivatives

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

	Commodity and Other Energy Management Contracts (in MMBTU)
Hedge designation	Gas Distribution	Retail Gas Marketing	Energy Marketing	Total
As of September 30, 2015
Commodity contracts	9,270,000	11,788,000	4,335,500	25,393,500
Energy management contracts (a)	—	—	32,211,282	32,211,282
Total (a)	9,270,000	11,788,000	36,546,782	57,604,782
As of December 31, 2014
Commodity contracts	6,840,000	7,951,000	3,446,720	18,237,720
Energy management contracts (b)	—	—	37,495,339	37,495,339
Total (b)	6,840,000	7,951,000	40,942,059	55,733,059

(a)  Includes an aggregate 1,246,230 MMBTU related to basis swap contracts in Energy Marketing.

(b)  Includes an aggregate 933,893 MMBTU related to basis swap contracts in Energy Marketing.

The Company was party to interest rate swaps designated as cash flow hedges with aggregate notional amounts of $120.0 million at September 30, 2015 and $124.4 million at December 31, 2014. The Company was party to interest rate swaps not designated as cash flow hedges with an aggregate notional amount of $1.2 billion at September 30, 2015 and $1.1 billion at December 31, 2014.

The fair value of interest rate and energy-related derivatives was as follows:

Fair Values of Derivative Instruments
Millions of dollars	Balance Sheet Location	Asset		Liability
As of September 30, 2015
Designated as hedging instruments
Interest rate contracts	Derivative financial instruments			$	4
	Other deferred credits and other liabilities			31
Commodity contracts	Other current assets			1
	Derivative financial instruments			6
Total				$	42
Not designated as hedging instruments
Interest rate contracts	Other deferred debits and other assets	$	6	—
	Derivative financial instruments	—		$	107
	Other deferred credits and other liabilities	—		60
Energy management contracts	Other current assets	10		2
	Derivative financial instruments	—		8
	Other deferred debits and other assets	5		—
	Other deferred credits and other liabilities	—		4
Total		$	21	$	181

Millions of dollars	Balance Sheet Location	Asset		Liability
As of December 31, 2014
Designated as hedging instruments
Interest rate contracts	Derivative financial instruments			$	5
	Other deferred credits and other liabilities			28
Commodity contracts	Other current assets			1
	Derivative financial instruments			11
Total				$	45
Not designated as hedging instruments
Interest rate contracts	Derivative financial instruments	—		$	207
	Other deferred credits and other liabilities	—		17
Commodity contracts	Other current assets	$	1	—
Energy management contracts	Other current assets	15		5
	Derivative financial instruments	—		10
	Other deferred debits and other assets	5		—
	Other deferred credits and other liabilities	—		5
Total		$	21	$	244

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

Derivatives Designated as Fair Value Hedges

The Company had no interest rate or commodity derivatives designated as fair value hedges for any period presented.

Derivatives in Cash Flow Hedging Relationships

	Loss Deferred in Regulatory Accounts							Loss Reclassified from Deferred Accounts into Income
	(Effective Portion)							(Effective Portion)
Millions of dollars	2015			2014			Location	2015			2014
Three Months Ended September 30,
Interest rate contracts	$	(3	)	$	(1	)	Interest expense	$	(1	)	$	(1	)
Nine Months Ended September 30,
Interest rate contracts	$	(3	)	$	(5	)	Interest expense	$	(2	)	$	(2	)

	Gain (Loss) Recognized in OCI, net of tax							Gain (Loss) Reclassified from AOCI into Income, net of tax
	(Effective Portion)							(Effective Portion)
Millions of dollars	2015			2014			Location	2015			2014
Three Months Ended September 30,
Interest rate contracts	$	(3	)	—			Interest expense	$	(2	)	$	(2	)
Commodity contracts	(4		)	$	(2	)	Gas purchased for resale	(1		)	—
Total	$	(7	)	$	(2	)		$	(3	)	$	(2	)
Nine Months Ended September 30,
Interest rate contracts	$	(3	)	$	(4	)	Interest expense	$	(6	)	$	(5	)
Commodity contracts	(5		)	1			Gas purchased for resale	(10		)	4
Total	$	(8	)	$	(3	)		$	(16	)	$	(1	)

As of September 30, 2015, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $4.0 million as an increase to gas cost and approximately $6.5 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels.  As of September 30, 2015, all of the Company’s commodity cash flow hedges settle by their terms before the end of the second quarter of 2018.

As of September 30, 2015, the Company expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $2.3 million as an increase to interest expense, assuming financial markets remain at their current levels.

Hedge Ineffectiveness

Ineffectiveness on interest rate hedges designated as cash flow hedges was insignificant during all periods presented.

Derivatives not designated as Hedging Instruments
	Loss Deferred in Regulatory Accounts							Gain Reclassified from Deferred Accounts into Income
Millions of dollars	2015			2014			Location	2015		2014
Three Months Ended September 30,
Interest rate contracts	$	(116	)	$	(35	)	Other income	—		$	5
Nine Months Ended September 30,
Interest rate contracts	$	(79	)	$	(220	)	Other income	$	5	$	60

As of September 30, 2015, the Company expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from derivatives not designated as hedges will include $0.6 million as an increase to interest expense.

Credit Risk Considerations

The Company limits credit risk in its commodity and interest rate derivatives activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. In this regard, the Company uses credit ratings provided by credit rating agencies and current market-based qualitative and quantitative data, as well as financial statements, to assess the financial health of counterparties. The Company uses standardized master agreements which may include collateral requirements. These master agreements permit the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements permit the secured party to demand the posting of cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with the Company's credit policies and due diligence. In addition, collateral agreements allow for the termination and liquidation of all positions in the event of a failure or inability to post collateral.

Certain of the Company’s derivative instruments contain contingent provisions that may require the Company to provide collateral upon the occurrence of specific events, primarily credit downgrades. As of September 30, 2015 and December 31, 2014, the Company had posted $148.4 million and $152.4 million, respectively, of collateral related to derivatives with contingent provisions that were in a net liability position. Collateral related to the positions expected to close in the next 12 months is recorded in Other Current Assets on the condensed consolidated balance sheets. Collateral related to noncurrent positions is recorded in Other within Deferred Debits and Other Assets on the condensed consolidated balance sheets. If all of the contingent features underlying these instruments had been fully triggered as of September 30, 2015 and December 31, 2014, the Company could have been required to post an additional $69.1 million and $129.8 million, respectively, of collateral with its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of September 30, 2015 and December 31, 2014 is $217.5 million and $282.2 million, respectively.

In addition, as of September 30, 2015 and December 31, 2014, the Company has collected no cash collateral related to interest rate derivatives with contingent provisions that are in a net asset position. If all the contingent features underlying these instruments had been fully triggered as of September 30, 2015 and December 31, 2014, the Company could request $2.8 million and $- million, respectively, of cash collateral from its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net asset position as of September 30, 2015 and December 31, 2014 is $2.8 million and $- million, respectively. In addition, as of September 30, 2015, the Company could have called on letters of credit in the amount of $3.0 million related to $15.0 million in commodity derivatives that are in a net asset position, compared to letters of credit of $9.2 million related to derivatives of $20.0 million at December 31, 2014, if all the contingent features underlying these instruments had been fully triggered.

Information related to the Company's offsetting of derivative assets follows:

	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position				Net Amount
Millions of dollars						Financial Instruments			Cash Collateral Received
As of September 30, 2015
Interest rate contracts	$	6	—	$	6	$	(3	)	—	$	3
Energy management contracts	15		—	15		—			—	15
Total	$	21	—	$	21	$	(3	)	—	$	18
Balance sheet location	Other current assets			$	10
	Other deferred debits and other assets			11
	Total			$	21

As of December 31, 2014
Commodity contracts	$	1	—	$	1	—	—	$	1
Energy management contracts	20		—	20		—	—	20
Total	$	21	—	$	21	—	—	$	21
Balance sheet location	Other current assets			$	16
	Other deferred debits and other assets			5
	Total			$	21

Information related to the Company's offsetting of derivative liabilities follows:

	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position						Net Amount
Millions of dollars						Financial Instruments			Cash Collateral Posted
As of September 30, 2015
Interest rate contracts	$	202	—	$	202	$	(3	)	$	(135	)	$	64
Commodity contracts	7		—	7		—			(6		)	1
Energy management contracts	14		—	14		—			(7		)	7
Total	$	223	—	$	223	$	(3	)	$	(148	)	$	72
Balance sheet location	Other current assets			$	3
	Derivative financial instruments			125
	Other deferred credits and other liabilities			95
	Total			$	223

As of December 31, 2014
Interest rate contracts	$	257	—	$	257	—	$	(131	)	$	126
Commodity contracts	12		—	12		—	(10		)	2
Energy management contracts	20		—	20		—	(11		)	9
Total	$	289	—	$	289	—	$	(152	)	$	137
Balance sheet location	Other current assets			$	6
	Derivative financial instruments			233
	Other deferred credits and other liabilities			50
	Total			$	289

SCEG

Derivative [Line Items]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

DERIVATIVE FINANCIAL INSTRUMENTS

Consolidated SCE&G recognizes all derivative instruments as either assets or liabilities in the statement of financial position and measures those instruments at fair value.  Consolidated SCE&G recognizes changes in the fair value of derivative instruments either in earnings or within regulatory assets or regulatory liabilities, depending upon the intended use of the derivative and the resulting designation. 

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

Interest Rate Swaps

Consolidated SCE&G synthetically converts variable rate debt to fixed rate debt using swaps that are designated as cash flow hedges. Periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense.

In anticipation of the issuance of debt, Consolidated SCE&G may use treasury rate locks or forward starting swap agreements. Pursuant to regulatory orders, interest rate derivatives entered into by SCE&G after October 2013 are not designated as cash flow hedges, and all related fair value changes and settlement amounts are recorded as regulatory assets or liabilities. Interest rate derivatives entered into by SCE&G before October 2013, and all such derivatives entered into by GENCO, were designated as cash flow hedges, and for such instruments only the effective portion of fair value changes and settlement amounts are recorded in regulatory assets or regulatory liabilities. Upon settlement, losses on swaps are amortized over the lives of related debt issuances, and gains are applied to under-collected fuel, are amortized to interest expense or are applied as otherwise directed by the SCPSC.

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

Quantitative Disclosures Related to Derivatives

GENCO was party to an interest rate swap designated as a cash flow hedge with a notional amount of $36.4 million at September 30, 2015 and $36.4 million at December 31, 2014. SCE&G was party to interest rate swaps not designated as cash flow hedges with an aggregate notional amount of $1.2 billion at September 30, 2015 and $1.1 billion at December 31, 2014, respectively.

The fair value of interest rate derivatives was as follows:

Fair Values of Derivative Instruments
		Fair Value
Millions of dollars	Balance Sheet Location	Asset		Liability
As of September 30, 2015
Designated as hedging instruments
Interest rate contracts	Derivative financial instruments			$	1
	Other deferred credits and other liabilities			10
Total				$	11
Not designated as hedging instruments
Interest rate contracts	Derivative financial instruments	—		$	107
	Other deferred debits and other assets	$	6
	Other deferred credits and other liabilities	—		60
Total		$	6	$	167
As of December 31, 2014
Designated as hedging instruments
Interest rate contracts	Derivative financial instruments			$	1
	Other deferred credits and other liabilities			8
Total				$	9
Not designated as hedging instruments
Interest rate contracts	Derivative financial instruments			$	207
	Other deferred credits and other liabilities			17
Total				$	224

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

Derivatives in Cash Flow Hedging Relationships

	Loss Deferred in Regulatory Accounts							Loss Reclassified from Deferred Accounts into Income
	(Effective Portion)							(Effective Portion)
Millions of dollars	2015			2014			Location	2015			2014
Three Months Ended September 30,
Interest rate contracts	$	(3	)	$	(1	)	Interest expense	$	(1	)	$	(1	)
Nine Months Ended September 30,
Interest rate contracts	$	(3	)	$	(5	)	Interest expense	$	(2	)	$	(2	)

As of September 30, 2015, Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $2.3 million as an increase to interest expense, assuming financial markets remain at their current levels.

Hedge Ineffectiveness

Ineffectiveness on interest rate hedges designated as cash flow hedges was insignificant during all periods presented.

Derivatives not designated as Hedging Instruments

	Loss Deferred in Regulatory Accounts							Gain Reclassified from Deferred Accounts into Income
Millions of dollars	2015			2014			Location	2015		2014
Three Months Ended September 30,
Interest rate contracts	$	(116	)	$	(35	)	Other income	—		$	5
Nine Months Ended September 30,
Interest rate contracts	$	(79	)	$	(220	)	Other income	$	5	$	60

As of September 30, 2015, Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from derivatives not designated as hedges will include $0.6 million as an increase to interest expense.

Credit Risk Considerations

Consolidated SCE&G limits credit risk in its derivatives activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. In this regard, Consolidated SCE&G uses credit ratings provided by credit rating agencies and current market-based qualitative and quantitative data as well as financial statements, to assess the financial health of counterparties. Consolidated SCE&G uses standardized master agreements which may include collateral requirements. These master agreements permit the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements permit the secured party to demand the posting of cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with Consolidated SCE&G's credit policies and due diligence. In addition, collateral agreements allow for the termination and liquidation of all positions in the event of a failure or inability to post collateral.

Certain of Consolidated SCE&G’s derivative instruments contain contingent provisions that may require Consolidated SCE&G to provide collateral upon the occurrence of specific events, primarily credit downgrades.  As of September 30, 2015 and December 31, 2014, Consolidated SCE&G had posted $108.9 million and $107.1 million, respectively, of collateral related to derivatives with contingent provisions that were in a net liability position.  Collateral related to the positions expected to close in the next 12 months are recorded in Other Current Assets on the condensed consolidated balance sheets. Collateral related to noncurrent positions is recorded in Other within Deferred Debits and Other Assets on the condensed consolidated balance sheets. If all of the contingent features underlying these instruments had been fully triggered as of September 30, 2015 and December 31, 2014, Consolidated SCE&G could have been required to post an additional $65.8 million and $125.9 million, respectively, of collateral with its counterparties.  The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of September 30, 2015 and December 31, 2014 is $174.7 million and $233.0 million, respectively.

In addition, as of September 30, 2015 and December 31, 2014, Consolidated SCE&G has collected no cash collateral related to interest rate derivatives with contingent provisions that are in a net asset position. If all the contingent features underlying these instruments had been fully triggered as of September 30, 2015 and December 31, 2014, Consolidated SCE&G could request $2.8 million and $- million, respectively, of cash collateral from its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net asset position as of September 30, 2015 and December 31, 2014 is $2.8 million and $- million, respectively.

Information related to Consolidated SCE&G's derivative assets follows:

	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position				Net Amount
Millions of dollars						Financial Instruments			Cash Collateral Received
As of September 30, 2015
Interest rate contracts	$	6	—	$	6	$	(3	)	—	$	3
Balance Sheet Location	Other deferred debits and other assets			$	6

As of December 31, 2014, Consolidated SCE&G had no derivative assets.

Information related to Consolidated SCE&G's derivative liabilities follows:

	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position						Net Amount
Millions of dollars						Financial Instruments			Cash Collateral Posted
As of September 30, 2015
Interest rate contracts	$	178	—	$	178	$	(3	)	$	(109	)	$	66
Balance Sheet Location	Derivative financial instruments			$	108
	Other deferred credits and other liabilities			70
	Total			$	178

As of December 31, 2014
Interest rate contracts	$	233	—	$	233	—	$	(107	)	$	126
Balance Sheet Location	Derivative financial instruments			$	208
	Other deferred credits and other liabilities			25
	Total			$	233

XML

LONG-TERM AND SHORT-TERM DEBT

9 Months Ended

Sep. 30, 2015

Debt Instrument [Line Items]

Long-term Debt [Text Block]

LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

In May 2014, SCE&G issued $300 million of 4.5% first mortgage bonds due June 1, 2064. Proceeds from this sale were used to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes.

On February 2, 2015, SCANA redeemed prior to maturity $150 million of its 7.7% junior subordinated notes at their face value.

In May 2015, SCE&G issued $500 million of 5.1% first mortgage bonds due June 1, 2065. Proceeds from this sale were used to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes.

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

Liquidity

SCANA, SCE&G (including Fuel Company) and PSNC Energy had available the following committed LOC, and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations: 

	SCANA						SCE&G						PSNC Energy
Millions of dollars	September 30, 2015			December 31, 2014			September 30, 2015			December 31, 2014			September 30, 2015			December 31, 2014
Lines of credit:
Total committed long-term	$	300		$	300		$	1,400		$	1,400		$	100		$	100
Outstanding commercial paper ( 270 or fewer days)	$	14		$	179		$	234		$	709		$	16		$	30
Weighted average interest rate	0.66		%	0.54		%	0.44		%	0.52		%	0.45		%	0.65		%
Letters of credit supported by LOC	$	3		$	3		$	0.3		$	0.3		—			—
Available	$	283		$	118		$	1,166		$	691		$	84		$	70

SCANA, SCE&G (including Fuel Company) and PSNC Energy are parties to five-year credit agreements in the amounts of $300 million, $1.2 billion (of which $500 million relates to Fuel Company) and $100 million, respectively, which expire in October 2019. In addition, SCE&G is a party to a three-year credit agreement in the amount of $200 million, which expires in October 2016. These credit agreements are used for general corporate purposes, including liquidity support for each company's commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, certain fossil fuels, and emission and other environmental allowances.  These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N.A. and Morgan Stanley Bank, N.A. each provide 10.7% of the aggregate $1.8 billion credit facilities, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A., Credit Suisse AG, Cayman Island Branch and UBS Loan Finance LLC each provide 8.9%, and Branch Banking and Trust Company, Union Bank, N.A. and U.S. Bank National Association each provide 6.3%.  Two other banks provide the remaining support. The Company pays fees to the banks as compensation for maintaining the committed lines of credit. Such fees were not material in any period presented.

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

SCEG

Debt Instrument [Line Items]

Long-term Debt [Text Block]

LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

In May 2014, SCE&G issued $300 million of 4.5% first mortgage bonds due June 1, 2064. Proceeds from this sale were used to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes.

In May 2015, SCE&G issued $500 million of 5.1% first mortgage bonds due June 1, 2065. Proceeds from this sale were used to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes.

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

Liquidity

SCE&G (including Fuel Company) had available the following committed LOC, and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations:

Millions of dollars	September 30, 2015			December 31, 2014
Lines of credit:
Total committed long-term	$	1,400		$	1,400
Outstanding commercial paper (270 or fewer days)	$	234		$	709
Weighted average interest rate	0.44		%	0.52		%
Letters of credit supported by LOC	$	0.3		$	0.3
Available	$	1,166		$	691

SCE&G and Fuel Company are parties to five-year credit agreements in the amount of $1.2 billion (of which $500 million relates to Fuel Company), which expire in October 2019. In addition, SCE&G is a party to a three-year credit agreement in the amount of $200 million, which expires in October 2016. These credit agreements are used for general corporate purposes, including liquidity support for each company’s commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, certain fossil fuels, and emission and other environmental allowances. These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provide 10.7% of the aggregate $1.4 billion credit facilities, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A., Credit Suisse AG, Cayman Islands Branch and UBS Loan Finance LLC each provide 8.9% and Branch Banking and Trust Company, Union Bank, N.A. and U.S. Bank National Association each provide 6.3%.  Two other banks provide the remaining support. Consolidated SCE&G pays fees to the banks as compensation for maintaining the committed lines of credit. Such fees were not material in any period presented.

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

Consolidated SCE&G participates in a utility money pool with SCANA and certain other subsidiaries of SCANA. Money pool borrowings and investments bear interest at short-term market rates. Consolidated SCE&G’s interest income and expense from money pool transactions were not significant for any period presented. At September 30, 2015, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $41.2 million. At December 31, 2014, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $83.0 million and money pool investments due from an affiliate of $80.0 million.

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INCOME TAXES

9 Months Ended

Sep. 30, 2015

income tax [Line Items]

Income Tax Disclosure [Text Block]

INCOME TAXES

Between 2013 and 2015, in addition to filing current year tax returns, the Company amended certain of its tax returns. These returns claimed certain tax-defined research and development deductions and credits. In connection with these filings, the Company recorded an unrecognized tax benefit of $18 million. If recognized, $14 million of the tax benefit would affect the Company’s effective tax rate. It is reasonably possible that this tax benefit will increase by an additional $2 million within the next 12 months. It is also reasonably possible that this tax benefit may decrease by $8 million within the next 12 months. No other material changes in the status of the Company’s tax positions have occurred through September 30, 2015.

The Company recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses.  The Company has not recorded any interest expense or penalties associated with these positions.

SCEG

income tax [Line Items]

Income Tax Disclosure [Text Block]

INCOME TAXES

Between 2013 and 2015, in addition to filing current year tax returns, SCANA amended certain of its tax returns. These returns claimed certain tax-defined research and development deductions and credits. In connection with these filings, Consolidated SCE&G recorded an unrecognized tax benefit of $18 million. If recognized, $14 million of the tax benefit would affect Consolidated SCE&G’s effective tax rate. It is reasonably possible that this tax benefit will increase by an additional $2 million within the next 12 months. It is also reasonably possible that this tax benefit may decrease by $8 million. within the next 12 months. No other material changes in the status of Consolidated SCE&G’s tax positions have occurred through September 30, 2015.

                Consolidated SCE&G recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses.  Consolidated SCE&G has not recorded any interest expense or penalties associated with these positions.

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

9 Months Ended

Sep. 30, 2015

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

Fair Value Disclosures [Text Block]

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

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

	As of September 30, 2015				As of December 31, 2014
Millions of dollars	Level 1		Level 2		Level 1		Level 2
Assets:
Available for sale securities	$	13	—		$	13	—
Interest rate contracts	—		$	6	—		—
Commodity contracts	—		—		1		—
Energy management contracts	—		15		—		$	20
Liabilities:
Interest rate contracts	—		202		—		257
Commodity contracts	1		6		1		11
Energy management contracts	2		15		5		18

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

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

	September 30, 2015				December 31, 2014
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	6,034.3	$	6,623.3	$	5,697.2	$	6,592.1

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

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

SCEG

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

Fair Value Disclosures [Text Block]

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

Consolidated SCE&G’s interest rate swap agreements are valued using discounted cash flow models with independently sourced data.  Fair value Level 2 measurements were as follows:

Millions of dollars		September 30, 2015		December 31, 2014
Assets -	Interest rate contracts	$	6	—
Liabilities -	Interest rate contracts	178		$	233

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

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

	September 30, 2015				December 31, 2014
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	4,801.0	$	5,277.6	$	4,308.6	$	5,070.9

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

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

XML

RATE AND OTHER REGULATORY MATTERS (Details 2) $ in Millions	3 Months Ended			6 Months Ended	9 Months Ended		12 Months Ended
	Sep. 30, 2015 USD ($)	Sep. 30, 2014 USD ($)	Mar. 31, 2014 USD ($)	Jun. 30, 2015	Sep. 30, 2015 USD ($)	Sep. 30, 2014 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Sep. 30, 2013 USD ($)
Regulatory Assets
Regulatory Liabilities	$ 859.0				$ 859.0		$ 814.0
Public Utilities Base Fuel under Collected Balance Recovery Period					12
Regulatory Assets, Noncurrent	1,884.0				$ 1,884.0		$ 1,823.0
SCEG
Regulatory Assets
Public Utilities, Percent Increase (Decrease) in Retail Electric Rates					0.00%		0.00%	2.90%
Public Utilities Increase (Decrease) in Retail Electric Rates Approved under BLRA					$ 65.0		$ 66.0	$ 67.2
Public Utilities, Rate Calculation Basis					12-month rolling average
Fuel Costs					$ 10.3
Undercollected balance fuel	46.0				46.0
Public Utilities, Percent Increase (Decrease) in Retail Natural Gas Rates							0.60%
Regulatory Liabilities	641.0				641.0		$ 610.0
Annual Storm Damage Costs not offset by Amounts Recovered through Electric Rates					2.5
Carrying costs on deferred income tax assets	2.4	$ 1.6			6.5	$ 4.1
Derivative, Gain on Derivative							17.8
Storm Damage Reserve Cost Applied							5.0
Demand Side Management Program Costs, Noncurrent	32.0	$ 15.4			32.0	$ 15.4			$ 16.9
Amount Allowed to be Recovered through Electric Rates to Offset Incremental Storm Damage Costs					$ 100.0
Public Utilities Base Fuel under Collected Balance Recovery Period					12
Regulatory Assets, Noncurrent	1,808.0				$ 1,808.0		1,745.0
Demand side management recovery period					5
Storm Damage Reserve Applied To Offset Net Lost Margin Related To DSM			$ 5.0
Public Utilities changes in Retail Natural Gas Rates Approved under RSA							2.6
Amounts Recovered Through Electric Rates to offset Nuclear Related Outage Costs					$ 17.2
Public Utilities, Authorized Allowable Return on Common Equity, Percentage				11.00%	11.00%
PSNC Energy [Member]
Regulatory Assets
Public Utilities, Rate Calculation Basis			12
Other Regulatory Liability [Member]
Regulatory Assets
Regulatory Liabilities	3.0				$ 3.0		1.0
Asset Retirement Obligation Costs [Member]
Regulatory Assets
Regulatory Liabilities	729.0				729.0		703.0
Asset Retirement Obligation Costs [Member] | SCEG
Regulatory Assets
Regulatory Liabilities	520.0				520.0		505.0
Deferred Income Tax Charges [Member]
Regulatory Assets
Regulatory Liabilities	22.0				22.0		22.0
Deferred Income Tax Charges [Member] | SCEG
Regulatory Assets
Regulatory Liabilities	16.0				16.0		17.0
Storm damage reserve [Member]
Regulatory Assets
Regulatory Liabilities	6.0				6.0		6.0
Annual Storm Damage Costs not offset by Amounts Recovered through Electric Rates					2.5
Amount Allowed to be Recovered through Electric Rates to Offset Incremental Storm Damage Costs					100.0
Storm Damage Reserve Applied To Offset Net Lost Margin Related To DSM							5.0
Storm damage reserve [Member] | SCEG
Regulatory Assets
Regulatory Liabilities	6.0				6.0		6.0
Planned major maintenance [Member]
Regulatory Assets
Regulatory Liabilities	12.0				12.0		0.0
Planned major maintenance [Member] | SCEG
Regulatory Assets
Regulatory Liabilities	12.0				12.0		0.0
Amounts Recovered through Electric Rates to offset Turbine Expense					18.4
Deferred gains on interest rate derivatives [Member]
Regulatory Assets
Regulatory Liabilities	87.0				87.0		82.0
Deferred gains on interest rate derivatives [Member] | SCEG
Regulatory Assets
Regulatory Liabilities	87.0				$ 87.0		82.0
Pension costs, electric [Member] | SCEG
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period					30 years
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority	63.0				$ 63.0
Franchise agreement Costs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	23.0				23.0		26.0
Franchise agreement Costs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	23.0				23.0		26.0
Deferred Losses On Interest Rate Derivatives [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	538.0				538.0		453.0
Deferred Losses On Interest Rate Derivatives [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	538.0				538.0		453.0
Deferred Pollution Control Cost [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	35.0				35.0		36.0
Deferred Pollution Control Cost [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	35.0				35.0		36.0
Regulatory Clause Revenues, under-recovered [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	0.0				0.0		20.0
Regulatory Clause Revenues, under-recovered [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	0.0				0.0		20.0
Planned major maintenance [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	0.0				0.0		2.0
Planned major maintenance [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	0.0				$ 0.0		2.0
Asset Retirement Obligation Costs [Member]
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period					110 years
Regulatory Assets, Noncurrent	376.0				$ 376.0		366.0
Asset Retirement Obligation Costs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	356.0				356.0		347.0
unrecovered plant [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	128.0				128.0		137.0
unrecovered plant [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	128.0				128.0		137.0
Demand Side Management programs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	59.0				59.0		56.0
Demand Side Management programs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	59.0				59.0		56.0
Carrying cost on nuclear construction [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	15.0				15.0		9.0
Carrying cost on nuclear construction [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	15.0				15.0		9.0
Pipeline integerity management costs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	16.0				$ 16.0		9.0
Deferred Income Tax Charges [Member]
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period					85 years
Regulatory Assets, Noncurrent	284.0				$ 284.0		284.0
Deferred Income Tax Charges [Member] | SCEG
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period					85 years
Regulatory Assets, Noncurrent	278.0				$ 278.0		278.0
Environmental Restoration Costs [Member]
Regulatory Assets
MPG enviromental remediatio					24
Regulatory Assets, Noncurrent	39.0				$ 39.0		40.0
Environmental Restoration Costs [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	35.0				35.0		36.0
Pension Costs [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	328.0				$ 328.0		350.0
Pension Costs [Member] | SCEG
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period					12 years			30 years
Regulatory Assets, Noncurrent	296.0				$ 296.0		310.0
Pension costs, gas [Member] | SCEG
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period								14 years
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority	14.0				$ 14.0
Other Regulatory Assets [Member]
Regulatory Assets
Regulatory Noncurrent Asset, Amortization Period					30 years
Regulatory Assets, Noncurrent	43.0				$ 43.0		35.0
Other Regulatory Assets [Member] | SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	$ 45.0				$ 45.0		$ 35.0

XML

Dispositions (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Public Utilities, Property, Plant and Equipment, Net	$ 12,729.0	$ 12,232.0
Nonutility Property and Investments, Net	467.0	472.0
Assets, Current	1,221.0	2,145.0
Regulated Entity, Other Assets, Noncurrent	2,089.0	2,003.0
Assets held for sale	0.0	341.0
Liabilities, Current	1,294.0	2,533.0
Liabilities, Noncurrent	3,775.0	3,801.0
Liabilities held for sale		52.0
Estimated pre-tax gain on sale of CGT and SCI	$ 342.0
Assets Held-for-sale [Member] | CGT [Member]
Public Utilities, Property, Plant and Equipment, Net		288.4
Nonutility Property and Investments, Net		0.6
Assets, Current		6.5
Regulated Entity, Other Assets, Noncurrent		0.9
Assets held for sale		296.4
Assets Held-for-sale [Member] | SCANA Communications [Member]
Public Utilities, Property, Plant and Equipment, Net		0.0
Nonutility Property and Investments, Net		40.1
Assets, Current		3.9
Regulated Entity, Other Assets, Noncurrent		0.2
Assets held for sale		44.2
Assets Held-for-sale [Member] | Held for Sale, CGT and SCI [Member]
Public Utilities, Property, Plant and Equipment, Net		288.4
Nonutility Property and Investments, Net		40.7
Assets, Current		10.4
Regulated Entity, Other Assets, Noncurrent		1.1
Assets held for sale		340.6
Liabilities, Held for Sale [Member] | CGT [Member]
Liabilities, Current		3.5
Liabilities, Noncurrent		42.9
Liabilities held for sale		46.4
Liabilities, Held for Sale [Member] | SCANA Communications [Member]
Liabilities, Current		2.2
Liabilities, Noncurrent		3.1
Liabilities held for sale		5.3
Liabilities, Held for Sale [Member] | Held for Sale, CGT and SCI [Member]
Liabilities, Current		5.7
Liabilities, Noncurrent		46.0
Liabilities held for sale		$ 51.7

XML

Dispositions (Notes)

9 Months Ended

Sep. 30, 2015

Disposal groups [Abstract]

Disposal Group, Held for Sale [Text Block]

DISPOSITIONS

In December 2014, SCANA entered into definitive agreements to sell CGT and SCI. CGT is an interstate natural gas pipeline regulated by FERC that transports natural gas in South Carolina and southeastern Georgia, and it was sold to Dominion Resources, Inc. SCI provides fiber optic communications and other services and builds, manages and leases communications towers in several southeastern states, and it was sold to a subsidiary of Spirit Communications. These sales closed in the first quarter of 2015 and resulted in recognition of pre-tax gains totaling approximately $342 million. As further described in Note 1, the pre-tax gain from the sale of CGT is included within Operating Income and the pre-tax gain from the sale of SCI is included within Other Income (Expense) on the condensed consolidated income statement.

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

The carrying values of the assets and liabilities classified as held for sale in the consolidated balance sheet as of December 31, 2014, were as follows:

Millions of dollars	CGT		SCI		Total
Assets Held for Sale
Utility Plant, Net	$	288.4	—		$	288.4
Nonutility Property and Investments, Net	0.6		$	40.1	40.7
Current Assets	6.5		3.9		10.4
Deferred Debits and Other Assets	0.9		0.2		1.1
Total Assets Held for Sale	$	296.4	$	44.2	$	340.6
Liabilities Held for Sale
Current Liabilities	$	3.5	$	2.2	$	5.7
Deferred Credits and Other Liabilities	42.9		3.1		46.0
Total Liabilities Held for Sale	$	46.4	$	5.3	$	51.7

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DERIVATIVE FINANCIAL INSTRUMENTS (Tables)

9 Months Ended

Sep. 30, 2015

Derivative [Line Items]

Schedule of Derivative Instruments [Table Text Block]

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

	Commodity and Other Energy Management Contracts (in MMBTU)
Hedge designation	Gas Distribution	Retail Gas Marketing	Energy Marketing	Total
As of September 30, 2015
Commodity contracts	9,270,000	11,788,000	4,335,500	25,393,500
Energy management contracts (a)	—	—	32,211,282	32,211,282
Total (a)	9,270,000	11,788,000	36,546,782	57,604,782
As of December 31, 2014
Commodity contracts	6,840,000	7,951,000	3,446,720	18,237,720
Energy management contracts (b)	—	—	37,495,339	37,495,339
Total (b)	6,840,000	7,951,000	40,942,059	55,733,059

(a)  Includes an aggregate 1,246,230 MMBTU related to basis swap contracts in Energy Marketing.

(b)  Includes an aggregate 933,893 MMBTU related to basis swap contracts in Energy Marketing.

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

The fair value of interest rate and energy-related derivatives was as follows:

Fair Values of Derivative Instruments
Millions of dollars	Balance Sheet Location	Asset		Liability
As of September 30, 2015
Designated as hedging instruments
Interest rate contracts	Derivative financial instruments			$	4
	Other deferred credits and other liabilities			31
Commodity contracts	Other current assets			1
	Derivative financial instruments			6
Total				$	42
Not designated as hedging instruments
Interest rate contracts	Other deferred debits and other assets	$	6	—
	Derivative financial instruments	—		$	107
	Other deferred credits and other liabilities	—		60
Energy management contracts	Other current assets	10		2
	Derivative financial instruments	—		8
	Other deferred debits and other assets	5		—
	Other deferred credits and other liabilities	—		4
Total		$	21	$	181

Millions of dollars	Balance Sheet Location	Asset		Liability
As of December 31, 2014
Designated as hedging instruments
Interest rate contracts	Derivative financial instruments			$	5
	Other deferred credits and other liabilities			28
Commodity contracts	Other current assets			1
	Derivative financial instruments			11
Total				$	45
Not designated as hedging instruments
Interest rate contracts	Derivative financial instruments	—		$	207
	Other deferred credits and other liabilities	—		17
Commodity contracts	Other current assets	$	1	—
Energy management contracts	Other current assets	15		5
	Derivative financial instruments	—		10
	Other deferred debits and other assets	5		—
	Other deferred credits and other liabilities	—		5
Total		$	21	$	244

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

Derivatives in Cash Flow Hedging Relationships

	Loss Deferred in Regulatory Accounts							Loss Reclassified from Deferred Accounts into Income
	(Effective Portion)							(Effective Portion)
Millions of dollars	2015			2014			Location	2015			2014
Three Months Ended September 30,
Interest rate contracts	$	(3	)	$	(1	)	Interest expense	$	(1	)	$	(1	)
Nine Months Ended September 30,
Interest rate contracts	$	(3	)	$	(5	)	Interest expense	$	(2	)	$	(2	)

	Gain (Loss) Recognized in OCI, net of tax							Gain (Loss) Reclassified from AOCI into Income, net of tax
	(Effective Portion)							(Effective Portion)
Millions of dollars	2015			2014			Location	2015			2014
Three Months Ended September 30,
Interest rate contracts	$	(3	)	—			Interest expense	$	(2	)	$	(2	)
Commodity contracts	(4		)	$	(2	)	Gas purchased for resale	(1		)	—
Total	$	(7	)	$	(2	)		$	(3	)	$	(2	)
Nine Months Ended September 30,
Interest rate contracts	$	(3	)	$	(4	)	Interest expense	$	(6	)	$	(5	)
Commodity contracts	(5		)	1			Gas purchased for resale	(10		)	4
Total	$	(8	)	$	(3	)		$	(16	)	$	(1	)

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

Derivatives not designated as Hedging Instruments
	Loss Deferred in Regulatory Accounts							Gain Reclassified from Deferred Accounts into Income
Millions of dollars	2015			2014			Location	2015		2014
Three Months Ended September 30,
Interest rate contracts	$	(116	)	$	(35	)	Other income	—		$	5
Nine Months Ended September 30,
Interest rate contracts	$	(79	)	$	(220	)	Other income	$	5	$	60

Offseting Assets [Table Text Block]

Information related to the Company's offsetting of derivative assets follows:

	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position				Net Amount
Millions of dollars						Financial Instruments			Cash Collateral Received
As of September 30, 2015
Interest rate contracts	$	6	—	$	6	$	(3	)	—	$	3
Energy management contracts	15		—	15		—			—	15
Total	$	21	—	$	21	$	(3	)	—	$	18
Balance sheet location	Other current assets			$	10
	Other deferred debits and other assets			11
	Total			$	21

As of December 31, 2014
Commodity contracts	$	1	—	$	1	—	—	$	1
Energy management contracts	20		—	20		—	—	20
Total	$	21	—	$	21	—	—	$	21
Balance sheet location	Other current assets			$	16
	Other deferred debits and other assets			5
	Total			$	21

Offsetting Liabilities [Table Text Block]

Information related to the Company's offsetting of derivative liabilities follows:

	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position						Net Amount
Millions of dollars						Financial Instruments			Cash Collateral Posted
As of September 30, 2015
Interest rate contracts	$	202	—	$	202	$	(3	)	$	(135	)	$	64
Commodity contracts	7		—	7		—			(6		)	1
Energy management contracts	14		—	14		—			(7		)	7
Total	$	223	—	$	223	$	(3	)	$	(148	)	$	72
Balance sheet location	Other current assets			$	3
	Derivative financial instruments			125
	Other deferred credits and other liabilities			95
	Total			$	223

As of December 31, 2014
Interest rate contracts	$	257	—	$	257	—	$	(131	)	$	126
Commodity contracts	12		—	12		—	(10		)	2
Energy management contracts	20		—	20		—	(11		)	9
Total	$	289	—	$	289	—	$	(152	)	$	137
Balance sheet location	Other current assets			$	6
	Derivative financial instruments			233
	Other deferred credits and other liabilities			50
	Total			$	289

SCEG

Derivative [Line Items]

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

The fair value of interest rate derivatives was as follows:

Fair Values of Derivative Instruments
		Fair Value
Millions of dollars	Balance Sheet Location	Asset		Liability
As of September 30, 2015
Designated as hedging instruments
Interest rate contracts	Derivative financial instruments			$	1
	Other deferred credits and other liabilities			10
Total				$	11
Not designated as hedging instruments
Interest rate contracts	Derivative financial instruments	—		$	107
	Other deferred debits and other assets	$	6
	Other deferred credits and other liabilities	—		60
Total		$	6	$	167
As of December 31, 2014
Designated as hedging instruments
Interest rate contracts	Derivative financial instruments			$	1
	Other deferred credits and other liabilities			8
Total				$	9
Not designated as hedging instruments
Interest rate contracts	Derivative financial instruments			$	207
	Other deferred credits and other liabilities			17
Total				$	224

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

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

Derivatives in Cash Flow Hedging Relationships

	Loss Deferred in Regulatory Accounts							Loss Reclassified from Deferred Accounts into Income
	(Effective Portion)							(Effective Portion)
Millions of dollars	2015			2014			Location	2015			2014
Three Months Ended September 30,
Interest rate contracts	$	(3	)	$	(1	)	Interest expense	$	(1	)	$	(1	)
Nine Months Ended September 30,
Interest rate contracts	$	(3	)	$	(5	)	Interest expense	$	(2	)	$	(2	)

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

Derivatives not designated as Hedging Instruments

	Loss Deferred in Regulatory Accounts							Gain Reclassified from Deferred Accounts into Income
Millions of dollars	2015			2014			Location	2015		2014
Three Months Ended September 30,
Interest rate contracts	$	(116	)	$	(35	)	Other income	—		$	5
Nine Months Ended September 30,
Interest rate contracts	$	(79	)	$	(220	)	Other income	$	5	$	60

Offseting Assets [Table Text Block]

Information related to Consolidated SCE&G's derivative assets follows:

	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position				Net Amount
Millions of dollars						Financial Instruments			Cash Collateral Received
As of September 30, 2015
Interest rate contracts	$	6	—	$	6	$	(3	)	—	$	3
Balance Sheet Location	Other deferred debits and other assets			$	6

Offsetting Liabilities [Table Text Block]

Information related to Consolidated SCE&G's derivative liabilities follows:

	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position						Net Amount
Millions of dollars						Financial Instruments			Cash Collateral Posted
As of September 30, 2015
Interest rate contracts	$	178	—	$	178	$	(3	)	$	(109	)	$	66
Balance Sheet Location	Derivative financial instruments			$	108
	Other deferred credits and other liabilities			70
	Total			$	178

As of December 31, 2014
Interest rate contracts	$	233	—	$	233	—	$	(107	)	$	126
Balance Sheet Location	Derivative financial instruments			$	208
	Other deferred credits and other liabilities			25
	Total			$	233

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

XML

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

XML

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

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

9 Months Ended

Sep. 30, 2015

Significant Accounting Policies

Significant Accounting Policies [Text Block]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Plant to be Retired

At December 31, 2014, SCE&G expected to retire three units that are or were coal-fired by 2020, which was prior to the end of the previously estimated useful lives over which the units were being depreciated. As such, these units were identified as Plant to be Retired. In the third quarter of 2015, in connection with the adoption of a customary depreciation study and related analysis, SCE&G determined that these three units would not likely be retired by 2020 (see Note 2), and their depreciation rates were set to recover the units' net carrying value over their respective revised useful lives. Accordingly, the net carrying value of these units is no longer classified as Plant to be Retired at September 30, 2015.

Asset Management and Supply Service Agreements

PSNC Energy utilizes asset management and supply service agreements with counterparties for certain natural gas storage facilities.  Such counterparties held 50% and 48% of PSNC Energy’s natural gas inventory at September 30, 2015

and December 31, 2014, respectively, with a carrying value of $19.1 million and $26.1 million, respectively, through either capacity release or agency relationships.  Under the terms of the asset management agreements, PSNC Energy receives storage asset management feesof which 75% are credited to rate payers. No fees are received under supply service agreements. The agreements, which expired on March 31, 2015, were replaced with similar agreements scheduled to expire March 31, 2017.

Income Statement Presentation

The Company presents the revenues and expenses of its regulated businesses and its retail natural gas marketing businesses (including those activities of segments described in Note 10) within operating income, and it presents all other activities within other income (expense). Consistent with this presentation, the gain on the sale of CGT is reflected within operating income and the gain on the sale of SCI is reflected within other income (expense).

New Accounting Matters

In April 2014, the FASB issued accounting guidance for reporting discontinued operations and disclosures of disposals of components of an entity. Under this guidance, only those discontinued operations which represent a strategic shift that will have a major effect on an entity’s operations and financial results should be reported as discontinued operations in the financial statements. As permitted, the Company adopted this guidance for the period ended December 31, 2014.

In May 2014, the FASB issued accounting guidance for revenue arising from contracts with customers that supersedes most current revenue recognition guidance, including industry-specific guidance. The new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. After the FASB's delay in the effective date of the revenue guidance by one year, the Company is required to adopt this guidance in the first quarter of 2018 and early adoption is permitted beginning in the first quarter of 2017. The Company has not determined the impact this guidance will have on its results of operations, cash flows or financial position.

In April 2015, the FASB issued accounting guidance intended to simplify the presentation of debt issuance costs by requiring that such costs be deducted from the carrying amounts related to debt liabilities when presented in the balance sheet. As permitted, the Company expects to early adopt this guidance in the fourth quarter of 2015.  The Company does not expect the adoption of this guidance to have a significant impact on its financial position.  The guidance will not affect the Company’s results of operations or cash flows.

In April 2015, the FASB issued accounting guidance related to fees paid by a customer in a cloud computing arrangement.  Among other things, the guidance clarifies how to account for a software license element included in a cloud computing arrangement, and makes explicit that a cloud computing arrangement not containing a software license element should be accounted for as a service contract. The Company has evaluated this guidance and has determined it will not significantly impact the Company’s results of operations, cash flows or financial position. The Company expects to adopt this guidance in the first quarter of 2016.

In July 2015, the FASB issued accounting guidance intended to simplify the subsequent measurement of inventory cost by requiring most inventory to be measured at the lower of cost and net realizable value. The Company expects to adopt this guidance when required in the first quarter of 2017. The Company is evaluating this guidance and has not determined what impact it will have on its results of operations, cash flows or financial position.

SCEG

Significant Accounting Policies

Significant Accounting Policies [Text Block]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Variable Interest Entities

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

GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $489 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission allowances. See also Note 4.

Plant to be Retired

At December 31, 2014, SCE&G expected to retire three units that are or were coal-fired by 2020, which was prior to the end of the previously estimated useful lives over which the units were being depreciated. As such, these units were identified as Plant to be Retired. In the third quarter of 2015, in connection with the adoption of a customary depreciation study and related analysis, SCE&G determined that these three units would not likely be retired by 2020 (see Note 2), and their depreciation rates were set to recover the units' net carrying value over their respective revised useful lives. Accordingly, the net carrying value of these units is no longer classified as Plant to be Retired at September 30, 2015.

New Accounting Matters

In May 2014, the FASB issued accounting guidance for revenue arising from contracts with customers that supersedes most current revenue recognition guidance, including industry-specific guidance. The new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. After the FASB's delay in the effective date of the revenue guidance by one year, Consolidated SCE&G is required to adopt this guidance in the first quarter of 2018 and early adoption is permitted beginning in the first quarter of 2017.  Consolidated SCE&G has not determined the impact this guidance will have on its results of operations, cash flows or financial position.

In April 2015, the FASB issued accounting guidance intended to simplify the presentation of debt issuance costs by requiring that such costs be deducted from the carrying amounts related to debt liabilities when presented in the balance sheet. As permitted, Consolidated SCE&G expects to early adopt this guidance in the fourth quarter of 2015.  Consolidated SCE&G does not expect the adoption of this guidance to have a significant impact on its financial position.  The guidance will not affect Consolidated SCE&G’s results of operations or cash flows.

In April 2015, the FASB issued accounting guidance related to fees paid by a customer in a cloud computing arrangement.  Among other things, the guidance clarifies how to account for a software license element included in a cloud computing arrangement, and makes explicit that a cloud computing arrangement not containing a software license element should be accounted for as a service contract. Consolidated SCE&G has evaluated this guidance and has determined it will not significantly impact its results of operations, cash flows or financial position. Consolidated SCE&G expects to adopt this guidance in the first quarter of 2016.

In July 2015, the FASB issued accounting guidance intended to simplify the subsequent measurement of inventory cost by requiring most inventory to be measured at the lower of cost and net realizable value when presented in the balance sheet. Consolidated SCE&G expects to adopt this guidance in the first quarter of 2017. Consolidated SCE&G is evaluating this guidance and has not determined what impact it will have on its results of operations, cash flows or financial position.

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FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Tables)

9 Months Ended

Sep. 30, 2015

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

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

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

	As of September 30, 2015				As of December 31, 2014
Millions of dollars	Level 1		Level 2		Level 1		Level 2
Assets:
Available for sale securities	$	13	—		$	13	—
Interest rate contracts	—		$	6	—		—
Commodity contracts	—		—		1		—
Energy management contracts	—		15		—		$	20
Liabilities:
Interest rate contracts	—		202		—		257
Commodity contracts	1		6		1		11
Energy management contracts	2		15		5		18

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

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

	September 30, 2015				December 31, 2014
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	6,034.3	$	6,623.3	$	5,697.2	$	6,592.1

SCEG

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

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

Fair value Level 2 measurements were as follows:

Millions of dollars		September 30, 2015		December 31, 2014
Assets -	Interest rate contracts	$	6	—
Liabilities -	Interest rate contracts	178		$	233

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

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

	September 30, 2015				December 31, 2014
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	4,801.0	$	5,277.6	$	4,308.6	$	5,070.9

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LONG-TERM AND SHORT-TERM DEBT (Details 2) - USD ($) $ in Millions	3 Months Ended	6 Months Ended		9 Months Ended
	Mar. 31, 2015	Jun. 30, 2015	Jun. 30, 2014	Sep. 30, 2015	Dec. 31, 2014
Lines of credit:
Line of Credit Facility, Maximum Borrowing Capacity				$ 1,800.0
Commercial Paper Maximum Term				270
Number of other banks (in entities)				2
Debt Instrument, Interest Rate Terms	0.077	.051
Bank of America, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				10.70%
Morgan Stanly Bank, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				10.70%
BB&T Bank [Domain]
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				8.90%
CREDIT SUISSE (US) [Member]
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				8.90%
Credit Suisse AG, Cayman Islands Branch (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				10.70%
JPMorgan Chase Bank, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				8.90%
Mizuho Corporate Bank, Ltd (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				8.90%
TD Bank, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				8.90%
UBS Loan Finance LLC (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				8.90%
Deutsche Bank AG New York Branch [Member] [Member]
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				6.30%
Union Bank, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				6.30%
US Bank National Association (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				6.30%
Two other banks [Domain]
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				6.00%
JP Morgan Chase, Mizuho Corp, TD Bank, Credit Suisse AG ,Cayman Islands Branch and UBS Loan Finance [Member]
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				8.90%
SCEG
Debt Instrument [Line Items]
Proceeds from Issuance of First Mortgage Bond		$ 500.0	$ 300.0
Due to Affiliate, Current				$ 125.0	$ 180.0
Debt Instruments [Abstract]
Face value of Industrial Revenue Bonds issued, proceeds of which were availed as loan				67.8
Lines of credit:
Line of Credit Facility, Maximum Borrowing Capacity				1,200.0
3 year credit agreement				200.0
Related Party Transaction, Due from (to) Related Party, Current				$ 41.2	83.0
Due from Other Related Parties, Current					80.0
Debt Instrument, Interest Rate Terms		0.051	.045
SCEG | Bank of America, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				10.70%
SCEG | Morgan Stanly Bank, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				10.70%
SCEG | CREDIT SUISSE (US) [Member]
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				8.90%
SCEG | Credit Suisse AG, Cayman Islands Branch (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				10.70%
SCEG | JPMorgan Chase Bank, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				8.90%
SCEG | Mizuho Corporate Bank, Ltd (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				8.90%
SCEG | TD Bank, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				8.90%
SCEG | UBS Loan Finance LLC (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				8.90%
SCEG | Deutsche Bank AG New York Branch [Member] [Member]
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				6.30%
SCEG | Union Bank, N.A. (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				6.30%
SCEG | US Bank National Association (Member)
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				6.30%
SCEG | Two other banks [Domain]
Lines of credit:
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				6.00%
Parent Company [Member]
Lines of credit:
Line of Credit Facility, Maximum Borrowing Capacity				$ 300.0	300.0
Commercial Paper				$ 14.0	$ 179.0
Commercial paper, weighted average interest rate (as a percent)				0.66%	0.54%
Letters of credit supported by LOC				$ (3.0)	$ (3.0)
Line of Credit Facility, Remaining Borrowing Capacity				283.0	118.0
SCE&G (including Fuel Company)
Lines of credit:
Line of Credit Facility, Maximum Borrowing Capacity				1,400.0	1,400.0
Commercial Paper				$ 234.0	$ 709.0
Commercial paper, weighted average interest rate (as a percent)				0.44%	0.52%
Letters of credit supported by LOC				$ (0.3)	$ (0.3)
Line of Credit Facility, Remaining Borrowing Capacity				1,166.0	691.0
3 year credit agreement		$ 200.0
Long-term Line of Credit		$ 1,400.0
Fuel Company
Lines of credit:
Line of Credit Facility, Maximum Borrowing Capacity				500.0
PSNC Energy
Lines of credit:
Line of Credit Facility, Maximum Borrowing Capacity				100.0	100.0
Commercial Paper				16.0	$ 30.0
Commercial paper, weighted average interest rate (as a percent)					0.65%
Letters of credit supported by LOC				0.0	$ 0.0
Line of Credit Facility, Remaining Borrowing Capacity				$ 84.0	$ 70.0

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AFFILIATED TRANSACTIONS - SCEG

9 Months Ended

Sep. 30, 2015

SCEG

Related Party Transactions Disclosure [Text Block]

AFFILIATED TRANSACTIONS

CGT transports natural gas to SCE&G to serve retail gas customers and certain electric generation requirements.  Prior to January 31, 2015, CGT was a wholly-owned subsidiary of SCANA, and SCE&G's transactions with CGT prior to January 31, 2015 were affiliated transactions. SCE&G's affiliated purchases from CGT totaled approximately $6.9 million for the three months ended September 30, 2014, and $3.4 million and $21.6 million for the nine months ended September 30, 2015 and 2014, respectively.  SCE&G's affiliated payables to CGT for transportation services were $3.3 million at December 31, 2014, and SCE&G's affiliated receivables from CGT related to such transportation services were $1.2 million at December 31, 2014.

SCE&G purchases natural gas and related pipeline capacity from SEMI to serve its retail gas customers and certain electric generation requirements.  Such purchases totaled approximately $34.0 million and $46.8 million for the three months ended September 30, 2015 and 2014, respectively, and $101.4 million and $154.1 million for the nine months ended September 30, 2015 and 2014, respectively.  SCE&G’s payables to SEMI for such purchases were $9.6 million at September 30, 2015 and $12.6 million at December 31, 2014.

SCE&G owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and sale of refined coal to reduce emissions. SCE&G accounts for this investment using the equity method.  SCE&G’s total purchases from this affiliate were $66.3 million and $82.4 million for the three months ended September 30, 2015 and 2014, respectively, and $186.0 million and $191.9 million for the nine months ended September 30, 2015 and 2014, respectively.  SCE&G’s total sales to this affiliate were $65.9 million and $82.0 million for the three months ended September 30, 2015 and 2014, respectively, and $185.1 million and $190.9 million for the nine months ended September 30, 2015 and 2014, respectively. SCE&G’s receivable from this affiliate was $21.6 million at September 30, 2015 and $27.8 million at December 31, 2014.  SCE&G’s payable to this affiliate was $21.8 million at September 30, 2015 and $27.9 million at December 31, 2014.

SCANA Services provides the following services to Consolidated SCE&G, which are rendered at direct or allocated cost: information systems services, telecommunications services, customer services, marketing and sales, human resources, corporate compliance, purchasing, financial services, risk management, public affairs, legal services, investor relations, gas supply and capacity management, strategic planning, general administrative services, and retirement benefits. In addition, SCANA Services processes and pays invoices for Consolidated SCE&G and is reimbursed. Costs for these services were $80.8 million and $65.0 million for the three months ended September 30, 2015 and 2014, respectively, and $226.0 million and $211.4 million for the nine months ended September 30, 2015 and 2014, respectively. Consolidated SCE&G's payables to SCANA Services for these services were $37.2 million at September 30, 2015 and $47.3 million at December 31, 2014.

Money pool borrowings from an affiliate are described in Note 4.