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, 2013

OR

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

For the Transition Period from to

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 ¨  South Carolina Electric & Gas Company Yes x No ¨

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 ¨  South Carolina Electric & Gas Company Yes x No ¨

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

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

SCANA Corporation Yes ¨ No x  South Carolina Electric & Gas Company Yes¨ 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, 2013
SCANA Corporation	Without Par Value	140,548,894
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, 2013

			Page
Cautionary Statement Regarding Forward-Looking Information			3
Definitions			4
PART I. FINANCIAL INFORMATION
SCANA Corporation Financial Section			6
	Item 1.	Financial Statements	7
		Condensed Consolidated Balance Sheets	7
		Condensed Consolidated Statements of Income	9
		Condensed Consolidated Statements of Comprehensive Income	10
		Condensed Consolidated Statements of Cash Flows	11
		Notes to Condensed Consolidated Financial Statements	12
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	35
	Item 4.	Controls and Procedures	36
South Carolina Electric & Gas Company Financial Section			37
	Item 1.	Financial Statements	38
		Condensed Consolidated Balance Sheets	38
		Condensed Consolidated Statements of Income	40
		Condensed Consolidated Statements of Comprehensive Income	41
		Condensed Consolidated Statements of Cash Flows	42
		Notes to Condensed Consolidated Financial Statements	43
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	56
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	59
	Item 4.	Controls and Procedures	60
PART II. OTHER INFORMATION			60
	Item 5.	Other Information	60
	Item 6.	Exhibits	60
Signatures			61
Exhibit Index			62

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

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

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

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

(12) the results of efforts to license, site, construct and finance facilities for electric generation and transmission;

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

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

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

(16) 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;

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

(18) labor disputes;

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

(20) changes in taxes;

(21) inflation or deflation;

(22) compliance with regulations;

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

(24) the other risks and uncertainties described from time to time in the periodic 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
BACT	Best Available Control Technology
BLRA	Base Load Review Act
CA	The designation for a specific pre-fabricated construction module, such as module CA20
CAA	Clean Air Act, as amended
CAIR	Clean Air Interstate Rule
CEO	Chief Executive Officer
CFO	Chief Financial Officer
CGT	Carolina Gas Transmission Corporation
COL	Combined Construction and Operating License
Company	SCANA, together with its consolidated subsidiaries
Consolidated SCE&G	SCE&G and its consolidated affiliates
Consortium	A consortium consisting of Westinghouse Electric Company LLC and Stone and Webster, Inc., a subsidiary of Chicago Bridge & Iron Company N.V.
CSAPR	Cross-State Air Pollution Rule
CUT	Customer Usage Tracker
DHEC	South Carolina Department of Health and Environmental Control
DOJ	United States Department of Justice
DSM Programs	Demand reduction and energy efficiency programs
EIZ Credits	South Carolina Capital Investment Tax Credits (formerly known as Economic Impact Zone Income Tax Credits)
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
eWNA	Pilot Electric Weather Normalization Adjustment
FERC	United States Federal Energy Regulatory Commission
Fuel Company	South Carolina Fuel Company, Inc.
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
JEDA	South Carolina Jobs-Economic Development Authority
LOC	Lines of Credit
MGP	Manufactured Gas Plant
MMBTU	Million British Thermal Units
MW	Megawatt
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
NRC	United States Nuclear Regulatory Commission

4

NSPS	New Source Performance Standards
NSR	New Source Review
NYMEX	New York Mercantile Exchange
OCI	Other Comprehensive Income
ORS	South Carolina Office of Regulatory Staff
PGA	Purchased Gas Adjustment
Price-Anderson	Price-Anderson Indemnification Act
PRP	Potentially Responsible Party
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
SCEUC	South Carolina Energy Users Committee
SCPSC	Public Service Commission of South Carolina
SEC	United States Securities and Exchange Commission
SEMI	SCANA Energy Marketing, Inc.
Summer Station	V. C. Summer Nuclear Station
VIE	Variable Interest Entity

5

SCANA CORPORATION

FINANCIAL SECTION

6

PART I.  FINANCIAL INFORMATION

ITEM 1. F INANCIAL STATEMENTS

SCANA CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited) 

Millions of dollars	September 30, 2013			December 31, 2012
Assets
Utility Plant In Service	$	12,119		$	11,865
Accumulated Depreciation and Amortization	(3,965		)	(3,811		)
Construction Work in Progress	2,558			2,084
Plant to be Retired, Net	344			362
Nuclear Fuel, Net of Accumulated Amortization	296			166
Goodwill, net of writedown of $230	230			230
Utility Plant, Net	11,582			10,896
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation of $148 and $139	315			306
Assets held in trust, net-nuclear decommissioning	98			94
Other investments	91			87
Nonutility Property and Investments, Net	504			487
Current Assets:
Cash and cash equivalents	30			72
Receivables, net of allowance for uncollectible accounts of $5 and $7	710			780
Inventories (at average cost):
Fuel and gas supply	263			305
Materials and supplies	145			136
Prepayments and other	194			223
Deferred income taxes	9			11
Total Current Assets	1,351			1,527
Deferred Debits and Other Assets:
Regulatory assets	1,333			1,464
Other	227			242
Total Deferred Debits and Other Assets	1,560			1,706
Total	$	14,997		$	14,616

7

Millions of dollars	September 30, 2013		December 31, 2012
Capitalization and Liabilities
Common Equity	$	4,598	$	4,154
Long-Term Debt, net	5,431		4,949
Total Capitalization	10,029		9,103
Current Liabilities:
Short-term borrowings	378		623
Current portion of long-term debt	19		172
Accounts payable	340		428
Customer deposits and customer prepayments	83		86
Taxes accrued	137		164
Interest accrued	75		82
Dividends declared	71		66
Derivative financial instruments	12		80
Other	88		110
Total Current Liabilities	1,203		1,811
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,723		1,653
Deferred investment tax credits	33		36
Asset retirement obligations	576		561
Postretirement benefits	263		387
Regulatory liabilities	1,007		882
Other	163		183
Total Deferred Credits and Other Liabilities	3,765		3,702
Commitments and Contingencies (Note 9)	—		—
Total	$	14,997	$	14,616

See Notes to Condensed Consolidated Financial Statements.

8

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	2013			2012			2013			2012
Operating Revenues:
Electric	$	704		$	714		$	1,898		$	1,851
Gas - regulated	128			109			667			513
Gas - nonregulated	219			215			813			690
Total Operating Revenues	1,051			1,038			3,378			3,054
Operating Expenses:
Fuel used in electric generation	196			239			570			617
Purchased power	19			9			35			20
Gas purchased for resale	265			248			1,076			837
Other operation and maintenance	167			165			513			510
Depreciation and amortization	95			89			282			267
Other taxes	54			50			164			156
Total Operating Expenses	796			800			2,640			2,407
Operating Income	255			238			738			647
Other Income (Expense):
Other income	10			13			36			39
Other expense	(10		)	(9		)	(32		)	(29		)
Interest charges, net of allowance for borrowed funds used during construction of $4, $3, $10 and $8	(74		)	(75		)	(223		)	(219		)
Allowance for equity funds used during construction	9			6			19			13
Total Other Expense	(65		)	(65		)	(200		)	(196		)
Income Before Income Tax Expense	190			173			538			451
Income Tax Expense	59			51			170			136
Net Income	$	131		$	122		$	368		$	315
Per Common Share Data
Basic Earnings Per Share of Common Stock	$	0.94		$	0.93		$	2.67		$	2.41
Diluted Earnings Per Share of Common Stock	$	0.94		$	0.91		$	2.66		$	2.37
Weighted Average Common Shares Outstanding (millions)										0
Basic	140.1			131.4			138.0			130.8
Diluted	140.1			133.8			138.6			133.1
Dividends Declared Per Share of Common Stock	$	0.5075		$	0.495		$	1.5225		$	1.485

See Notes to Condensed Consolidated Financial Statements.

9

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited) 

	Three Months Ended September 30,					Nine Months Ended September 30,
Millions of dollars	2013			2012		2013		2012
Net Income	$	131		$	122	$	368	$	315
Other Comprehensive Income (Loss), net of tax:
Unrealized gains (losses) on cash flow hedging activities arising during period, net of tax of $-, $-, $2 and $(4)	(1		)	1		3		(6		)
Losses on cash flow hedging activities reclassified to net income, net of tax of $1, $2, $4 and $11	2			3		7		17
Employee benefit plan remeasurement and curtailment gains arising during the period, net of tax of $2, $-, $2 and $-	4			—		4		—
Deferred employee benefit plan costs reclassified to net income, net of tax of $-, $-, $- and $-	1			—		1		1
Other Comprehensive Income	6			4		15		12
Total Comprehensive Income	$	137		$	126	$	383	$	327

Accumulated other comprehensive loss totaled $69.9 million as of September 30, 2013 and $85.6 million as of December 31, 2012.

See Notes to Condensed Consolidated Financial Statements.

10

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited) 

	Nine Months Ended September 30,
Millions of dollars	2013			2012
Cash Flows From Operating Activities:
Net income	$	368		$	315
Adjustments to reconcile net income to net cash provided from operating activities:
Deferred income taxes, net	62			74
Depreciation and amortization	294			277
Amortization of nuclear fuel	42			38
Allowance for equity funds used during construction	(19		)	(13		)
Changes in certain assets and liabilities:
Receivables	70			46
Inventories	(8		)	(34		)
Prepayments and other	8			58
Regulatory liabilities	78			47
Accounts payable	(32		)	(7		)
Taxes accrued	(27		)	(21		)
Interest accrued	(7		)	4
Regulatory assets	142			(2		)
Postretirement benefits	(133		)	3
Other assets	(46		)	4
Other liabilities	(13		)	(21		)
Net Cash Provided From Operating Activities	779			768
Cash Flows From Investing Activities:
Property additions and construction expenditures	(868		)	(868		)
Proceeds from investments (including derivative collateral posted)	199			364
Purchase of investments (including derivative collateral posted)	(161		)	(326		)
Proceeds from interest rate contract settlement	43			14
Payments upon interest rate contract settlement	(49		)	(51		)
Net Cash Used For Investing Activities	(836		)	(867		)
Cash Flows From Financing Activities:
Proceeds from issuance of common stock	272			73
Proceeds from issuance of long-term debt	451			763
Repayment of long-term debt	(256		)	(274		)
Dividends	(207		)	(192		)
Short-term borrowings, net	(245		)	(259		)
Net Cash Provided From Financing Activities	15			111
Net Increase (Decrease) In Cash and Cash Equivalents	(42		)	12
Cash and Cash Equivalents, January 1	72			29
Cash and Cash Equivalents, September 30	$	30		$	41
Supplemental Cash Flow Information:
Cash paid for– Interest (net of capitalized interest of $10 and $8)	$	222		$	212
– Income taxes	70			67
Noncash Investing and Financing Activities:
Accrued construction expenditures	97			79
Capital leases	5			4
Nuclear fuel purchase	98			—

 See Notes to Condensed Consolidated Financial Statements.

11

SCANA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

For the Three and Nine Months Ended September 30, 2013 and 2012

(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, 2012. 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

In 2012, SCE&G announced its intention to retire six coal-fired units by 2018, subject to future developments in environmental regulations, among other matters. These units had an aggregate generating capacity (summer 2012) of 730 MW. One of these units (90 MW) was retired in 2012 and its net carrying value is recorded in regulatory assets as unrecovered plant (see Note 2). In June 2013, SCE&G approved a plan to accelerate the retirement of two more of these units (295 MW) by the end of 2013, and in the third quarter SCE&G received SCPSC approval to record the net carrying value of these units in regulatory assets as unrecovered plant once they are retired and to amortize such costs over the units' previously estimated remaining useful lives. The net carrying value of the remaining units to be retired (including these two units) is included in Plant to be Retired, Net in the consolidated financial statements. In connection with their retirement, SCE&G expects to be allowed a recovery of and a return on the net carrying value of the remaining units through rates. In the meantime, these units remain in rate base, and SCE&G continues to depreciate them using composite straight-line rates approved by the SCPSC.

Earnings Per Share

The Company computes basic earnings per share by dividing net income by the weighted average number of common shares outstanding for the period.  The Company computes diluted earnings per share using this same formula after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method.  The Company has issued no securities that would have an antidilutive effect on earnings per share.

Reconciliations of the weighted average number of common shares for basic and diluted earnings per share computation purposes are as follows:     

	Third Quarter		Year to Date
Millions	2013	2012	2013	2012
Weighted Average Shares Outstanding - Basic	140.1	131.4	138.0	130.8
Effect of dilutive equity forward shares	—	2.4	0.6	2.3
Weighted Average Shares - Diluted	140.1	133.8	138.6	133.1

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 47% and 44% of PSNC Energy’s natural gas inventory at September 30, 2013

and December 31, 2012, respectively, with a carrying value of $23.2 million and $19.6 million, respectively, through either capacity release or agency relationships.  Under the terms of the asset management agreements, PSNC Energy receives storage asset management fees. The agreements expire March 31, 2015. 

12

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. In April 2012, the SCPSC approved SCE&G's request to decrease the total fuel cost component of its retail electric rates, and approved a settlement agreement among SCE&G, the ORS and SCEUC in which SCE&G agreed to recover an amount equal to its under-collected balance of base fuel and variable environmental costs as of April 30, 2012, or $80.6 million, over a 12-month period beginning with the first billing cycle of May 2012.

This April 2012 order was superseded, in part, by a December 2012 rate order in which the SCPSC authorized SCE&G to reduce the base fuel cost component of its retail electric rates and, in doing so, stated that SCE&G may not adjust its base fuel cost component prior to the last billing cycle of April 2014, except where necessary due to extraordinary unforeseen economic or financial conditions.  In February 2013, in connection with its annual review of base rates for fuel costs, SCE&G requested authorization to reduce its environmental fuel cost component effective with the first billing cycle of May 2013.  Consistent with the December 2012 rate order, SCE&G did not request any adjustment to its base fuel cost component.  On March 14, 2013, SCE&G, ORS and the SCEUC entered into a settlement agreement accepting the proposed lower environmental fuel cost component effective with the first billing cycle of May 2013, and providing for the accrual of certain debt-related carrying costs on a portion of the undercollected balance of fuel costs. The SCPSC issued an order dated April 30, 2013, adopting and approving the settlement agreement and approving SCE&G's total fuel cost component.

Electric - Base Rates

On December 19, 2012, the SCPSC approved a 4.23% overall increase in SCE&G's retail electric base rates, effective January 1, 2013, and authorized an allowed return on common equity of 10.25%. The SCPSC also approved a mid-period reduction to the cost of fuel component in rates (as discussed above), a reduction in the DSM Programs component rider to retail rates, and the recovery of and a return on the net carrying value of certain retired generating plant assets described below. By order dated February 7, 2013, the SCPSC denied the SCEUC's petition for rehearing of this order and the order was not appealed.

The eWNA is designed to mitigate the effects of abnormal weather on residential and commercial customers' bills and is based on a 15 year historical average of temperatures. In connection with the December 2012 rate order, SCE&G agreed to perform a study of alternative structures for the eWNA. The study was completed and filed with the SCPSC on June 28, 2013. In the study, SCE&G proposed that no adjustment or modification to the eWNA be made at this time. On November 1, 2013, the ORS filed a report with the SCPSC recommending that the eWNA be terminated with the last billing cycle for December 2013. SCE&G will be working with the ORS to address its recommendation. SCE&G cannot predict what action the SCPSC may take, if any.

In February 2013, SCE&G filed an IRP with the SCPSC. The IRP evaluates future electric generation needs based on a variety of factors, including customer energy demands, EPA regulations, reserve margins and fuel costs. The IRP identified a total of six coal-fired units that SCE&G retired or intends to retire by 2018, subject to future developments in environmental regulations, among other matters. One of these units was retired in 2012, and its net carrying value is recorded in regulatory assets as unrecovered plant and is being amortized over its previously estimated remaining useful life. The net carrying value of the remaining units is included in Plant to be Retired, Net in the consolidated financial statements. In connection with their retirement, SCE&G expects to be allowed a recovery of and a return on the net carrying value of these remaining units through rates. In the meantime, these units remain in rate base, and SCE&G continues to depreciate them using composite straight-line rates approved by the SCPSC. As discussed in Note 1, SCE&G approved a plan to accelerate the retirement of two of the units by the end of 2013 and has received SCPSC approval to record the net carrying value of these units in regulatory assets as unrecovered plant once they are retired.

SCE&G's DSM Programs for electric customers provide for an annual rider, approved by the SCPSC, to allow recovery of the costs and net lost revenue associated with the DSM Programs, along with an incentive for investing in such programs. SCE&G submits annual filings regarding the DSM Programs, net lost revenues, program costs, incentives and net program benefits. The SCPSC has approved the following rate changes pursuant to annual DSM Programs filings, which changes became effective as indicated:

13

Year	Effective	Amount
2013	First billing cycle of May	$16.9 million
2012	First billing cycle of May	$19.6 million

In addition, the SCPSC approved the deferral of an additional $10.3 million of net lost revenues and provided for their recovery over a 12-month period beginning with the first billing cycle in May 2014.

SCE&G's initial authorization to operate its DSM Programs expires November 30, 2013. On May 31, 2013, SCE&G filed a request with the SCPSC for approval to extend the operation of its portfolio of DSM Programs.  SCE&G also requested approval to continue the use of the annual rate rider which (i) maintains the same terms and conditions currently in effect for the recovery of costs associated with the proposed DSM Programs, the net lost revenue associated with its DSM Programs, and an appropriate incentive for investing in such programs, and (ii) modifies the opt-out requirements for industrial customers.  SCE&G requested that the proposed DSM Programs and rate rider authorization be effective December 1, 2013.  

On October 21, 2013, SCE&G entered into a Settlement Agreement with ORS, Wal-Mart Stores East, LP, Sam’s East, Inc. and the SCEUC. Under the Settlement Agreement, the settling parties agreed that SCE&G’s revised portfolio of DSM Programs should be approved as filed by SCE&G.  As for the annual rate rider, the settling parties agreed that SCE&G should be allowed to (i) continue to defer and amortize all prudently incurred costs for the DSM Programs over five years with carrying costs, (ii) calculate the net lost revenues component of the DSM Programs rider utilizing a rolling three year period of program history, and (iii) continue to recover a shared savings incentive, among other things.  The settling parties also agreed that SCE&G’s DSM Programs should continue for six years. Two other parties in the case did not execute the Settlement Agreement.  A public hearing on this matter was held on October 24, 2013, and the SCPSC's ruling is pending.

Electric – BLRA

In November 2012, the SCPSC approved an updated construction schedule and additional updated capital costs of $278 million (SCE&G's portion in 2007 dollars). The November 2012 order approved additional identifiable capital costs of approximately $1 million (SCE&G's portion in 2007 dollars) related to new federal healthcare laws, information security measures, and certain minor design modifications; approximately $8 million (SCE&G's portion in 2007 dollars) related to transmission infrastructure; and approximately $132 million (SCE&G's portion in 2007 dollars) related to additional labor for the oversight of the New Units during construction and for preparing to operate the New Units, and facilities and information technology systems required to support the New Units and their personnel. In addition, the order approved revised substantial completion dates for the New Units based on the March 30, 2012 issuance of the COL and the amounts agreed upon by SCE&G and the Consortium in July 2012 to resolve claims for costs related to COL delays, design modifications of the shield building and certain pre-fabricated structural modules for the New Units and unanticipated rock conditions at the site. Thereafter, two parties filed separate petitions requesting that the SCPSC reconsider its November 2012 order. On December 12, 2012, the SCPSC denied both petitions. In March 2013, both parties appealed the SCPSC's order to the South Carolina Supreme Court. SCE&G is unable to predict the outcome of these appeals. For further discussion of new nuclear construction matters, see Note 9.

Under the BLRA, SCE&G is allowed to 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. Requested rate adjustments are 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 the following rate changes under the BLRA effective for bills rendered on and after October 30 in the years indicated:

Year	Action			Amount
2013	2.9	%	Increase	$67.2 million
2012	2.3	%	Increase	$52.1 million

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Gas

SCE&G

The RSA is designed to reduce the volatility of costs charged to customers by allowing for 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 years indicated:

Year	Action			Amount
2013	No change			-
2012	2.1	%	Increase	$7.5 million

On June 5, 2013, SCE&G submitted its annual RSA filing with the SCPSC for the 12-month period ending March 31, 2013. SCE&G earned a return on its gas distribution operations, after proforma adjustments, that is within the range of its allowable rate of return on common equity. The SCPSC approved SCE&G’s annual RSA filing on October 9, 2013, with no change in rates.

SCE&G's natural gas tariffs include a PGA clause that provides for the recovery of actual gas costs incurred. 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. The 2012 annual PGA hearing to review SCE&G's gas purchasing policies and procedures was held in November 2012 before the SCPSC. The SCPSC issued an order in December 2012 finding that SCE&G's gas purchasing policies and practices during the review period of August 1, 2011 through July 31, 2012, were reasonable and prudent. SCE&G’s 2013 annual PGA hearing was held on November 7, 2013, and the SCPSC's ruling is pending.

PSNC Energy

PSNC Energy is subject to a Rider D rate mechanism which allows it to recover from customers all prudently incurred gas costs and certain uncollectible expenses related to gas cost.  The Rider D rate mechanism also allows PSNC Energy to recover, in any manner authorized by the NCUC, losses on negotiated gas and transportation sales.

PSNC Energy’s rates are established 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 with the NCUC 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 September 2013, in connection with PSNC Energy's 2013 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, 2013.

Regulatory Assets and Regulatory Liabilities

The Company’s cost-based, rate-regulated utilities recognize in their financial statements certain revenues and expenses in different time periods than do enterprises that are not rate-regulated.  As a result, the Company has recorded regulatory assets and regulatory liabilities which are summarized in the following tables.  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, 2013		December 31, 2012
Regulatory Assets:
Accumulated deferred income taxes	$	254	$	254
Under-collections - electric fuel adjustment clause	52		66
Environmental remediation costs	42		44
AROs and related funding	359		319
Franchise agreements	32		36
Deferred employee benefit plan costs	319		460
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	126		151
Deferred pollution control costs	37		38
Unrecovered plant	19		20
Other	93		70
Total Regulatory Assets	$	1,333	$	1,464

Regulatory Liabilities:
Accumulated deferred income taxes	$	19	$	21
Asset removal costs	718		692
Storm damage reserve	27		27
Monetization of bankruptcy claim	30		32
Deferred gains on interest rate derivatives	203		110
Planned major maintenance	10		—
Total Regulatory Liabilities	$	1,007	$	882

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 70 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 during annual hearings which are not expected to be recovered in retail electric rates within 12 months. 

Environmental remediation costs represent costs associated with the assessment and clean-up of MGP sites currently or formerly owned by the Company.  These regulatory assets are expected to be recovered over periods of up to approximately 26 years.

ARO and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station and conditional AROs.  These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 90 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 began amortizing these amounts through cost of service rates in February 2003 over approximately 20 years.

Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under generally accepted accounting principles. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. In connection with the December 2012 rate order, approximately $63 million of deferred pension costs for electric operations are to be recovered through utility rates over approximately 30 years. In connection with the October 2013 RSA order, approximately $14 million of deferred pension costs for gas operations are to be recovered through utility rates 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, as approved pursuant to specific SCPSC orders.  SCE&G collects $18.4 million annually for fossil fueled turbine/generation equipment maintenance.  Through December 31, 2012, nuclear refueling charges were accrued during each 18-month refueling outage cycle as a component of cost of service. In connection with the December 2012 rate order, effective January 1, 2013, SCE&G began to collect and accrue $17.2 million annually for nuclear-related refueling charges.

Deferred losses or gains on interest rate derivatives generally represent the unrealized losses or gains from fair value adjustments and payments made or received upon termination of certain interest rate derivatives.  These amounts are expected to be amortized to interest expense over the lives of the underlying debt, up to approximately 30 years, unless, in the case of gains, such amounts are applied otherwise at the direction of regulators.

Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the scrubbers installed at Wateree and Williams Stations pursuant to specific regulatory orders.  Such costs are being recovered through utility rates over periods up to approximately 30 years. 

Unrecovered plant represents the net book value of a coal-fired generating unit retired from service prior to being fully depreciated. Pursuant to the December 2012 rate order, SCE&G is amortizing these amounts over the unit's previously estimated remaining useful life of approximately 14 years. Unamortized amounts are included in rate base.

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.

The monetization of bankruptcy claim represents proceeds from the sale of a bankruptcy claim which are being amortized into operating revenue through February 2024.

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 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.

3.COMMON EQUITY

Changes in common equity during the nine months ended September 30, 2013 and 2012 were as follows:

Millions of dollars	2013			2012
Balance at January 1,	$	4,154		$	3,889
Common stock issued	273			73
Dividends declared	(212		)	(194		)
Comprehensive income	383			327
Balance as of September 30,	$	4,598		$	4,095

SCANA had 200 million shares of common stock authorized as of September 30, 2013 and December 31, 2012, of which 140.2 million and 132.0 million were issued and outstanding at September 30, 2013 and December 31, 2012, respectively.

On March 5, 2013, SCANA settled all forward sales contracts related to its common stock through the issuance of approximately 6.6 million common shares, resulting in net proceeds of approximately $196.2 million.

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Reclassifications of gains (losses) from AOCI into earnings, net of taxes, were as follows:

Millions of dollars	2013			2012			Income Statement Line Item Affected
Three months ended September 30,
Interest rate contracts	$	(2	)	$	(2	)	Increase in interest expense
Commodity contracts	—			(1		)	Increase in gas purchased for resale
Deferred employee benefit plan costs	(1		)	—
Total reclassifications	$	(3	)	$	(3	)
Nine months ended September 30,
Interest rate contracts	$	(5	)	$	(5	)	Increase in interest expense
Commodity contracts	(2		)	(12		)	Increase in gas purchased for resale
Deferred employee benefit plan costs	(1		)	(1		)
Total reclassifications	$	(8	)	$	(18	)

For information related to the reclassification of deferred employee benefit amounts from AOCI, see Note 8.

4. LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

In June 2013, SCE&G issued $400 million of 4.60% first mortgage bonds due June 15, 2043. Proceeds from this sale were used to pay at maturity $150 million of its 7.125% first mortgage bonds due June 15, 2013, 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 January 2013, JEDA issued at a premium, for the benefit of SCE&G, $39.5 million of 4.0% tax-exempt industrial revenue bonds due February 1, 2028, and $14.7 million of 3.63% tax-exempt industrial revenue bonds due February 1, 2033. Proceeds from these sales were loaned by JEDA to SCE&G and, together with other available funds, were used to redeem prior to maturity $56.9 million of 5.2% industrial revenue bonds due November 1, 2027.

Substantially all of SCE&G’s and GENCO’s electric utility plant is pledged as collateral in connection with long-term debt. The Company is in compliance with all debt covenants.

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, 2013			December 31, 2012			September 30, 2013			December 31, 2012			September 30, 2013		December 31, 2012
Lines of credit:
Total committed long-term	$	300		$	300		$	1,400		$	1,400		$	100	$	100
LOC advances	—			—			—			—			—		—
Weighted average interest rate	—			—			—			—			—		—
Outstanding commercial paper (270 or fewer days)	$	68		$	142		$	310		$	449		—		$	32
Weighted average interest rate	0.43		%	0.58		%	0.30		%	0.42		%	—		0.44		%
Letters of credit supported by LOC	$	3		$	3		$	0.3		$	0.3		—		—
Available	$	229		$	155		$	1,090		$	951		$	100	$	68

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. In addition, SCE&G is party to a three-year credit agreement in the amount of $200 million. In October 2013, the term of each of

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these credit agreements was extended by one year, such that the five-year agreements expire in October 2018, and the three-year agreement 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 Branch Banking and Trust Company.  The letters of credit expire, subject to renewal, in the fourth quarter of 2014.

5.INCOME TAXES

No material changes in the status of the Company's tax positions have occurred through September 30, 2013.

During the third quarter of 2013, the State of North Carolina passed legislation that will lower the state corporate income tax rate from 6.9% to 6.0% in 2014 and 5.0% in 2015.  The change in income tax rates is not expected to have a material impact on the Company’s financial position, results of operations or cash flows. Additionally, during the third quarter of 2013, the IRS issued final regulations regarding the capitalization of certain costs for income tax purposes and re-proposed certain other related regulations (collectively referred to as tangible personal property regulations).  These regulations did not have a material impact on the Company's financial position, results of operations or cash flows.

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 other comprehensive income (loss) 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 the Audit Committee's 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.

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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.  In cases in which 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 lock or forward starting swap agreements that are designated as cash flow hedges.  Except as described in the following paragraph, the effective portions of changes in fair value and payments made or received upon termination of such agreements for regulated subsidiaries are recorded in regulatory assets or regulatory liabilities. For 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 authorization granted in October 2013, certain interest rate derivatives entered into by SCE&G will no longer be designated as cash flow hedges, and fair value changes and settlement amounts are to be recorded in its regulatory asset and liability accounts. Upon settlement, losses on swaps will be amortized over the lives of related debt issuances, and gains may be applied to undercollected fuel amounts or may be amortized to interest expense as 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, 2013
Commodity	8,820,000	10,407,000	3,078,500	22,305,500
Energy Management (a)	—	—	30,908,058	30,908,058
Total (a)	8,820,000	10,407,000	33,986,558	53,213,558
As of December 31, 2012
Commodity	5,170,000	6,490,000	4,877,000	16,537,000
Energy Management (b)	—	—	31,763,275	31,763,275
Total (b)	5,170,000	6,490,000	36,640,275	48,300,275

(a)  Includes an aggregate 674,308 MMBTU related to basis swap contracts in Energy Marketing.

(b)  Includes an aggregate 3,500,000 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 $663.8 million at September 30, 2013 and $1.1 billion at December 31, 2012.

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The fair value of energy-related derivatives and interest rate derivatives was reflected in the condensed consolidated balance sheet as follows:

	Fair Values of Derivative Instruments
	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
Millions of dollars	Location	Value		Location	Value
As of September 30, 2013
Derivatives designated as hedging instruments
Interest rate	Prepayments and other	$	83	Other current liabilities	$	5
	Other deferred debits and other assets	41		Other deferred credits and other liabilities	19
Commodity				Other current liabilities	3
Total		$	124		$	27
Derivatives not designated as hedging instruments
Commodity	Prepayments and other	$	1
Energy Management	Prepayments and other	5		Prepayments and other	$	1
				Other current liabilities	4
	Other deferred debits and other assets	5		Other deferred credits and other liabilities	5
Total		$	11		$	10

As of December 31, 2012
Derivatives designated as hedging instruments
Interest rate	Prepayments and other	$	42	Other current liabilities	$	70
	Other deferred debits and other assets	31		Other deferred credits and other liabilities	36
Commodity	Prepayments and other	1		Other current liabilities	4
Total		$	74		$	110
Derivatives not designated as hedging instruments
Commodity	Prepayments and other	$	1
Energy management	Prepayments and other	7		Prepayments and other	$	1
	Other deferred debits and other assets	6		Other current liabilities	6
				Other deferred debits and other assets	6
Total		$	14		$	13

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

Fair Value Hedges

With regard to the Company's interest rate swaps designated as fair value hedges, any gains or losses related to the swaps or the fixed rate debt are recognized in current earnings and included in interest expense.  The Company had no interest rate swaps designated as fair value hedges for any period presented, and the amortization of deferred gains on previously terminated swaps were not significant during any period presented.

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Cash Flow Hedges

Derivatives in Cash Flow Hedging Relationships

	Gain Deferred in Regulatory Accounts					Loss Reclassified from Deferred Accounts into Income
Millions of dollars	(Effective Portion)					(Effective Portion)
September 30,	2013		2012		Location	2013			2012
Three Months Ended
Interest rate	$	19	$	23	Interest expense	$	(1	)	$	(1	)
Nine Months Ended
Interest rate	$	115	$	51	Interest expense	$	(2	)	$	(2	)

	Gain (Loss) Recognized in OCI, net of tax							Loss Reclassified from AOCI into Income, net of tax
Millions of dollars	(Effective Portion)							(Effective Portion)
September 30,	2013			2012			Location	2013			2012
Three Months Ended
Interest rate	—			$	(1	)	Interest expense	$	(2	)	$	(2	)
Commodity	$	(1	)	2			Gas purchased for resale	—			(1		)
Total	$	(1	)	$	1			$	(2	)	$	(3	)
Nine Months Ended
Interest rate	$	4		$	(5	)	Interest expense	$	(5	)	$	(5	)
Commodity	(1		)	(1		)	Gas purchased for resale	(2		)	(12		)
Total	$	3		$	(6	)		$	(7	)	$	(17	)

As of September 30, 2013, the Company expects that during the next 12 months reclassifications from accumulated other comprehensive income (loss) to earnings arising from cash flow hedges will include approximately $2.0 million as an increase to gas cost and approximately $6.2 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels.  As of September 30, 2013, all of the Company’s commodity cash flow hedges settle by their terms before the end of 2015.

Derivatives not designated as Hedging Instruments		Loss Recognized in Income
Millions of dollars	Location	2013	2012
Three Months Ended September 30,
Commodity	Gas purchased for resale	—	—
Nine Months Ended September 30,
Commodity	Gas purchased for resale	—	$	(1	)

Hedge Ineffectiveness

Other losses recognized in income representing ineffectiveness on interest rate hedges designated as cash flow hedges were insignificant in each of the three and nine months ended September 30, 2013 and 2012, respectively.

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 on an ongoing basis. 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

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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, 2013 and December 31, 2012, the Company has posted $35.4 million and $78.3 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 Prepayments and other on the consolidated balance sheets. Collateral related to noncurrent positions is recorded in Other within Deferred Debits and Other Assets on the consolidated balance sheets. If all of the contingent features underlying these instruments had been fully triggered as of September 30, 2013 and December 31, 2012, the Company could have been required to post an additional $- million and $26.2 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, 2013 and December 31, 2012 is $35.3 million and $104.5 million, respectively.

In addition, as of September 30, 2013 and December 31, 2012, 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 were fully triggered as of September 30, 2013 and December 31, 2012, the Company could request $78.6 million and $32.1 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, 2013 and December 31, 2012 is $78.6 million and $32.1 million, respectively. In addition, at September 30, 2013, the Company could have called on letters of credit in the amount of $9 million related to $10 million in commodity derivatives that are in a net asset position, compared to letters of credit of $10 million related to derivatives of $13 million at December 31, 2012, 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 Not Offset in the Statement of Financial Position
Millions of dollars	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Financial Instruments			Cash Collateral Received	Net Amount
As of September 30, 2013
Interest rate	$	124	—	$	124	$	(3	)	—	$	121
Commodity	1		—	1		—			—	1
Energy Management	10		—	10		—			—	10
Total	$	135	—	$	135	$	(3	)	—	$	132
Balance sheet location	Prepayments and other			$	89
	Other deferred debits and other assets			46
	Total			$	135

23

As of December 31, 2012
Interest rate	$	73	—			$	73	$	(17	)	—	$	56
Commodity	2		—			2		—			—	2
Energy Management	13		$	(1	)	12		—			—	12
Total	$	88	$	(1	)	$	87	$	(17	)	—	$	70
Balance sheet location	Prepayments and other					$	50
	Other deferred debits and other assets					37
	Total					$	87

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

						Gross Amounts Not Offset in the Statement of Financial Position
Millions of dollars	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Financial Instruments			Cash Collateral Posted			Net Amount
As of September 30, 2013
Interest rate	$	24	—	$	24	$	(3	)	$	(21	)	—
Commodity	3		—	3		—			(1		)	$	2
Energy Management	10		—	10		—			(8		)	2
	$	37	—	$	37	$	(3	)	$	(30	)	$	4
Balance sheet location	Prepayments and other			$	1
	Other current liabilities			12
	Other deferred credits and other liabilities			24
	Total			$	37

As of December 31, 2012
Interest rate	$	106	—			$	106	$	(17	)	$	(67	)	$	22
Commodity	4		—			4		—			—			4
Energy Management	13		$	(1	)	12		—			(11		)	1
	$	123	$	(1	)	$	122	$	(17	)	$	(78	)	$	27
Balance sheet location	Other current liabilities					$	80
	Other deferred credits and other liabilities					42
	Total					$	122

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

		Fair Value Measurements Using
		Quoted Prices in
		Active Markets for		Significant Other
		Identical Assets		Observable Inputs
Millions of dollars		(Level 1)		(Level 2)
As of September 30, 2013
Assets -	Available for sale securities	$	9	—
	Interest rate contracts	—		$	124
	Commodity contracts	1		—
	Energy management contracts	—		10
Liabilities -	Interest rate contracts	—		24
	Commodity contracts	—		3
	Energy management contracts	—		13
As of December 31, 2012
Assets -	Available for sale securities	$	6	—
	Interest rate contracts	—		$	73
	Commodity contracts	1		1
	Energy management contracts	—		13
Liabilities -	Interest rate contracts	—		106
	Commodity contracts	—		4
	Energy management contracts	1		15

There were no fair value measurements based on significant unobservable inputs (Level 3) for either period presented.  In addition, 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 at September 30, 2013 and December 31, 2012 were as follows:

	September 30, 2013				December 31, 2012
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	5,450.9	$	5,936.7	$	5,121.0	$	6,115.0

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.

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8. EMPLOYEE BENEFIT PLANS

Pension and Other Postretirement Benefit Plans

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

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2013			2012			2013		2012
Three months ended September 30,
Service cost	$	5.1		$	5.0		$	1.2	$	1.1
Interest cost	9.5			10.9			2.8		2.9
Expected return on assets	(15.1		)	(15.0		)	—		—
Prior service cost amortization	1.5			1.8			0.1		0.2
Charge due to curtailment	9.9			—			—		—
Transition obligation amortization	—			—			—		0.2
Amortization of actuarial losses	3.5			4.5			0.8		—
Net periodic benefit cost	$	14.4		$	7.2		$	4.9	$	4.4

Nine months ended September 30,
Service cost	$	16.9		$	14.7		$	4.4	$	3.6
Interest cost	28.4			32.2			8.3		8.9
Expected return on assets	(45.8		)	(44.6		)	—		—
Prior service cost amortization	4.9			5.3			0.5		0.7
Charge due to curtailment	9.9			—			—		—
Transition obligation amortization	—			—			0.3		0.5
Amortization of actuarial losses	14.4			13.8			2.5		0.4
Net periodic benefit cost	$	28.7		$	21.4		$	16.0	$	14.1

No significant contribution to the pension trust is expected until after 2016, nor is a limitation on benefits payments expected to apply. As authorized by the SCPSC, prior to January 1, 2013 SCE&G deferred all pension expense related to retail electric and gas operations as a regulatory asset. In connection with the SCPSC's December 2012 rate order, effective January 1, 2013 SCE&G began recovering current pension expense related to retail electric operations through a rate rider that is adjusted annually. SCE&G also began recovering previously deferred pension expense as described in Note 2. Costs totaling $1.2 million and $2.4 million related to gas operations were deferred for the three and nine months ended September 30, 2013, respectively. Costs totaling $4.0 million and $11.4 million related to electric and gas operations were deferred for the corresponding periods in 2012. In connection with the October 2013 RSA order, beginning in November 2013, SCE&G will begin recovering current pension expense related to gas operations through cost of service rates and will begin recovering previously deferred costs as described in Note 2.

In the third quarter 2013, the Company amended its pension plan, such that pension benefits will no longer be offered to employees hired or rehired after December 31, 2013, and pension benefits for existing participants will no longer accrue for services performed or compensation earned after December 31, 2023.  As a result, the Company recorded a curtailment charge due to the accelerated amortization of prior service cost. Approximately $6.3 million of the curtailment charge was applicable to regulated operations and was deferred within regulatory assets. The Company expects to recover such deferred amounts through existing regulatory orders or to request recovery in future proceedings.

In connection with the pension plan amendment, the Company remeasured its pension obligation in the third quarter of 2013 using current assumptions for the discount rate and future salary increases. The pension plan amendment and remeasurement resulted in a reduction in the Company's pension obligation of approximately $128 million.

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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 the Company's nuclear power plant. Price-Anderson provides funds up to $13.6 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 $40.6 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 or other costs and expenses, 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.

Environmental

As part of the President's Climate Action Plan and by Presidential Memorandum issued June 25, 2013, the EPA was directed to issue a revised carbon standard for new power plants by September 20, 2013, to be made final as soon as appropriate. Standards, regulations, or guidelines are also required for existing units by June 1, 2014, to be made final no later than June 1, 2015. On September 20, 2013, EPA re-proposed NSPS under the CAA for emissions of carbon dioxide from newly constructed fossil fuel-fired units.The Company is evaluating the proposed rule, but cannot predict when it will become final, if at all, or what conditions it may impose on the Company, if any. The Company also cannot predict when rules will become final for existing units, if at all, or what conditions they may impose on the Company, if any. The Company expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates.

In 2005, the EPA issued the CAIR, which required the District of Columbia and 28 states to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels.  CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for nitrogen oxide and beginning in 2010 and 2015, respectively, for sulfur dioxide.  SCE&G and GENCO determined that additional air quality controls would be needed to meet the CAIR requirements.  On July 6, 2011 the EPA issued the CSAPR.  This rule replaced CAIR and the Clean Air Transport Rule proposed in July 2010 and is aimed at addressing power plant emissions that may contribute to air pollution in other states.  CSAPR requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide.  On December 30, 2011, the United States Court of Appeals for the District of Columbia issued an order staying CSAPR and reinstating CAIR pending resolution of an appeal of CSAPR. On August 21, 2012, the Court of Appeals vacated CSAPR and left CAIR in place. The EPA's petition for rehearing of the Court of Appeals' order was denied. In June, 2013, the U.S. Supreme Court agreed to review the Court of Appeals' decision and has scheduled oral arguments for December 10, 2013. Air quality control installations that SCE&G and GENCO have already completed have allowed the Company to comply with the reinstated CAIR. The Company will continue to pursue strategies to comply with all applicable environmental regulations.  Any costs incurred to comply with such regulations are expected to be recoverable through rates.

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In April 2012, the EPA's rule containing new standards for mercury and other specified air pollutants became effective.  The rule provides up to four years for facilities to meet the standards, and the Company's evaluation of the rule is ongoing. The Company's decision in 2012 to retire certain coal-fired units or convert them to burn natural gas and its project to build the New Units (see Note 1) along with other actions are expected to result in the Company's compliance with the EPA's rule.  Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates.

The EPA is conducting an enforcement initiative against the utilities industry related to the NSR provisions and the NSPS of the CAA. As part of the initiative, many utilities have received requests for information under Section 114 of the CAA. In addition, the DOJ, on behalf of the EPA, has taken civil enforcement action against several utilities. The primary basis for these actions is the assertion by the EPA that maintenance activities undertaken by the utilities at their coal-fired power plants constituted “major modifications” which required the installation of costly BACT. Some of the utilities subject to the actions have reached settlement. Though the Company cannot predict what action, if any, the EPA will initiate against it, any costs incurred are expected to be recoverable through rates.

The Company maintains an environmental assessment program to identify and evaluate its current and former operations sites that could require environmental clean-up.  As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site.  Environmental liabilities are accrued when the criteria for loss contingencies are met. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates.  Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations.  Amounts expected to be recovered through rates are recorded in regulatory assets and, if applicable, amortized over approved amortization periods. Other environmental costs are recorded to expense.

SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of byproduct 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 until 2017 and will cost an additional $21.2 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, 2013, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $37.1 million and are included in regulatory assets.

PSNC Energy is responsible for environmental clean-up at five sites in North Carolina on which MGP residuals are present or suspected.  PSNC Energy’s actual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other PRPs.  PSNC Energy has recorded a liability and associated regulatory asset of approximately $2.9 million, the estimated remaining liability at September 30, 2013. PSNC Energy expects to recover through rates any cost allocable to PSNC Energy arising from the remediation of these sites.

New Nuclear Construction

SCE&G, on behalf of itself and as agent for Santee Cooper, has contracted with the Consortium for the design and construction of the New Units at the site of Summer Station.  SCE&G's share of the estimated cash outlays (future value, excluding AFC) totals approximately $5.7 billion for plant and related transmission infrastructure costs, and is projected based on historical one-year and five-year escalation rates as required by the SCPSC.

The Consortium has experienced delays in the schedule for fabrication and delivery of sub-modules for the New Units. The fabrication and delivery of sub-modules are a focus area of the Consortium. The delivery schedule of sub-modules for structural module CA20, which is part of the auxiliary building, and CA01, which houses components inside the containment vessel, is now expected to support completion of on-site fabrication to allow them to be set on the nuclear island to the first New Unit during the first and third quarters of 2014, respectively. With this schedule, the Consortium continues to indicate that the substantial completion of the first New Unit is expected to be late 2017 or the first quarter of 2018 and that the substantial completion of the second New Unit is expected to be approximately twelve months after that of the first New Unit. The substantial completion dates currently approved by the SCPSC for the first and second New Units are March 15, 2017 and May 15, 2018, respectively. The SCPSC has also approved an 18-month contingency period beyond each of these dates. The preliminary expected new substantial completion dates are within the contingency periods. SCE&G cannot predict with certainty the extent to which the issue with the sub-modules or the delays in the substantial completion of the New Units will result in increased project costs. However, the preliminary estimate of the delay-related costs associated with SCE&G's share of the New Units is approximately $200 million. SCE&G has not accepted responsibility for any of these delay-related costs and expects to have further discussions with the Consortium regarding such responsibility. Additionally, the EPC Contract provides for liquidated damages in the event of a delay in the completion of the facility, which will also be included in discussions with

28

the Consortium. SCE&G believes its responsibility for any portion of the $200 million estimate should ultimately be substantially less, once all of the relevant factors are considered.

In addition to the above-described project delays, SCE&G is also aware of financial difficulties at a supplier responsible for certain significant components of the project.  The Consortium is monitoring the potential for disruptions in such equipment fabrication and possible responses.   Any disruptions could impact the project's schedule or costs, and such impacts could be material.

Subject to a national megawatt capacity limitation, the electricity to be produced by the New Units (advanced nuclear units, as defined) is expected to qualify for nuclear production tax credits under Section 45J of the Internal Revenue Code. Following the pouring of safety-related concrete for each of the Units’ reactor buildings (March 2013 for the first New Unit and November 2013 for the second New Unit), the Company has applied to the IRS for its allocations of such national megawatt capacity limitation. The IRS will forward the applications to the United States Department of Energy for appropriate certification.

The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve issues that arise during the course of constructing a project of this magnitude.  During the course of activities under the EPC Contract, issues have materialized that impact project budget and schedule. Claims specifically relating to COL delays,

design modifications of the shield building and certain pre-fabricated modules for the New Units and unanticipated rock

conditions at the site resulted in assertions of contractual entitlement to recover additional costs to be incurred. The resolution

of these specific claims is discussed in Note 2. SCE&G expects to resolve any disputes that arise in the future, including any which may arise with respect to the delay-related costs discussed above, through both the informal and formal procedures and anticipates that any additional costs that arise through such dispute resolution processes, as well as other costs identified from time to time, will be recoverable through rates.

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, as well as a request for information related to emergency plant staffing.  These conditions and requirements are responsive to the NRC's Near-Term Task Force report titled “Recommendations for Enhancing Reactor Safety in the 21st Century.”  This report was prepared in the wake of the March 2011 earthquake-generated tsunami, which severely damaged several nuclear generating units and their back-up cooling systems in Japan.  SCE&G continues to evaluate the impact of these conditions and requirements that may be imposed on the construction and operation of the New Units, and SCE&G prepared and submitted an integrated response plan for the New Units to the NRC in August 2013.  SCE&G cannot predict what additional regulatory or other outcomes may be implemented in the United States, or how such initiatives would impact SCE&G's existing Summer Station or the construction or operation of the New Units.

SCE&G understands that Santee Cooper continues to evaluate reduction of its level of participation in the New Units through potential sales of portions of its interest therein to third parties. SCE&G is unable to predict whether any change in Santee Cooper's ownership interest or the addition of new joint owners will increase project costs or delay the substantial completion dates of the New Units.  Any such project cost increase or delay could be material.

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 equity method investments and other nonreportable segments.  Nonreportable segments include a FERC-regulated interstate pipeline company and other companies that conduct nonregulated operations in energy-related and telecommunications industries.

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Millions of dollars	External Revenue			Intersegment Revenue			Operating Income			Net Income
Three Months Ended September 30, 2013
Electric Operations	$	704		$	2		$	257		n/a
Gas Distribution	123			—			(6		)	n/a
Retail Gas Marketing	67			—			n/a			$	(2	)
Energy Marketing	152			44			n/a			1
All Other	11			95			8			(3		)
Adjustments/Eliminations	(6		)	(141		)	(4		)	135
Consolidated Total	$	1,051		$	—		$	255		$	131

Nine Months Ended September 30, 2013
Electric Operations	$	1,898		$	6		$	588	n/a
Gas Distribution	657			—			94		n/a
Retail Gas Marketing	325			—			n/a		$	16
Energy Marketing	488			133			n/a		5
All Other	30			303			22		(2		)
Adjustments/Eliminations	(20		)	(442		)	34		349
Consolidated Total	$	3,378		$	—		$	738	$	368

Three Months Ended September 30, 2012
Electric Operations	$	714		$	2		$	243		n/a
Gas Distribution	107			—			(7		)	n/a
Retail Gas Marketing	64			—			n/a			$	(5	)
Energy Marketing	151			35			n/a			1
All Other	11			100			6			(3		)
Adjustments/Eliminations	(9		)	(137		)	(4		)	129
Consolidated Total	$	1,038		$	—		$	238		$	122

Nine Months Ended September 30, 2012
Electric Operations	$	1,851		$	7		$	534	n/a
Gas Distribution	507			—			81		n/a
Retail Gas Marketing	288			—			n/a		$	3
Energy Marketing	402			84			n/a		5
All Other	32			309			17		(2		)
Adjustments/Eliminations	(26		)	(400		)	15		309
Consolidated Total	$	3,054		$	—		$	647	$	315

	September 30,		December 31,
Segment Assets	2013		2012
Electric Operations	$	9,430	$	8,989
Gas Distribution	2,286		2,292
Retail Gas Marketing	131		153
Energy Marketing	124		122
All Other	1,287		1,415
Adjustments/Eliminations	1,739		1,645
Consolidated Total	$	14,997	$	14,616

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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, 2012.

RESULTS OF OPERATIONS

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2013

AS COMPARED TO THE CORRESPONDING PERIODS IN 2012

Earnings Per Share

Earnings per share was as follows:

	Third Quarter				Year to Date
	2013		2012		2013		2012
Basic earnings per share	$	0.94	$	0.93	$	2.67	$	2.41
Diluted earnings per share	$	0.94	$	0.91	$	2.66	$	2.37

Third Quarter and Year to Date

Basic earnings per share increased due to higher electric and gas margins. These margin increases were partially offset by higher operation and maintenance expenses, higher depreciation expense, higher property taxes and dilution from additional shares outstanding, as further discussed below.

Diluted earnings per share figures give effect to dilutive potential common stock using the treasury stock method. See Note 1 to the condensed consolidated financial statements.

Dividends Declared

SCANA’s Board of Directors has declared the following dividends on common stock during 2013:

Declaration Date	Dividend Per Share	Record Date	Payment Date
February 20, 2013	$0.5075	March 11, 2013	April 1, 2013
April 25, 2013	$0.5075	June 10, 2013	July 1, 2013
July 31, 2013	$0.5075	September 10, 2013	October 1, 2013
October 31, 2013	$0.5075	December 10, 2013	January 1, 2014

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 sales margin (including transactions with affiliates) was as follows:

	Third Quarter						Year to Date
Millions of dollars	2013		Change		2012		2013		Change		2012
Operating revenues	$	706.0	(1.4	)%	$	716.2	$	1,903.2	2.5	%	$	1,857.6
Less:  Fuel used in generation	197.6		(17.7	)%	240.0		574.5		(7.6	)%	621.9
Purchased power	18.9		*		9.4		34.7		76.1	%	19.7
Margin	$	489.5	4.9	%	$	466.8	$	1,294.0	6.4	%	$	1,216.0

* Greater than 100%

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Third Quarter

Electric margin increased primarily due to base rate increases under the BLRA of $15.5 million and higher retail electric base rates of $21.5 million approved in the December 2012 rate order.

Year to Date

Electric margin increased primarily due to base rate increases under the BLRA of $40.7 million and higher retail electric base rates of $53.5 million approved in the December 2012 rate order.

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

	Third Quarter				Year to Date
Classification	2013	Change		2012	2013	Change		2012
Residential	2,216	(6.6	)%	2,372	5,858	(0.1	)%	5,861
Commercial	2,073	(2.8	)%	2,132	5,520	(1.8	)%	5,622
Industrial	1,584	3.5	%	1,531	4,505	1.7	%	4,430
Other	164	(1.8	)%	167	442	(1.6	)%	449
Total Retail Sales	6,037	(2.7	)%	6,202	16,325	(0.2	)%	16,362
Wholesale	245	(63.8	)%	677	736	(62.0	)%	1,935
Total Sales	6,282	(8.7	)%	6,879	17,061	(6.8	)%	18,297

Third Quarter

Retail sales volume decreased primarily due to weather and lower average use, partially offset by customer growth. The decrease in wholesale sales is primarily due to the expiration of two customer contracts.

Year to Date

Retail sales volume decreased primarily due to lower average use, partially offset by customer growth and the effects of weather. The decrease in wholesale sales is primarily due to the expiration of two customer contracts.

Gas Distribution

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

	Third Quarter						Year to Date
Millions of dollars	2013		Change		2012		2013		Change		2012
Operating revenues	$	124.1	16.0	%	$	107.0	$	658.0	29.8	%	$	507.0
Less:  Gas purchased for resale	67.7		26.8	%	53.4		375.9		57.1	%	239.2
Margin	$	56.4	5.2	%	$	53.6	$	282.1	5.3	%	$	267.8

Third Quarter and Year to Date

Margin increased primarily due to the SCPSC-approved increase in base rates under the RSA which became effective with the first billing cycle of November 2012, as well as residential and commercial customer growth and increased industrial usage. 

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Sales volumes (in MMBTU) by class, including transportation, were as follows:

	Third Quarter				Year to Date
Classification (in thousands)	2013	Change		2012	2013	Change		2012
Residential	1,995	5.9	%	1,883	27,235	35.8	%	20,052
Commercial	4,129	5.9	%	3,898	19,774	16.7	%	16,946
Industrial	5,141	4.1	%	4,939	16,740	8.6	%	15,410
Transportation	10,316	11.4	%	9,264	31,303	10.2	%	28,417
Total	21,581	8.0	%	19,984	95,052	17.6	%	80,825

Third Quarter and Year to Date

Total sales volumes increased primarily due to customer growth and increased industrial usage. For year to date, the increase is also due to the effects of weather.

Retail Gas Marketing

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

	Third Quarter								Year to Date
Millions of dollars	2013			Change		2012			2013		Change		2012
Operating revenues	$	66.8		4.9	%	$	63.7		$	324.9	12.9	%	$	287.8
Net income (loss)	(3.8		)	(19.1	)%	(4.7		)	15.6		*		3.2

 * Greater than 100%

Third Quarter and Year to Date

Changes in operating revenues and net income (loss) are due to higher demand in 2013 primarily as a result of  weather.

Energy Marketing

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

	Third Quarter						Year to Date
Millions of dollars	2013		Change		2012		2013		Change		2012
Operating revenues	$	195.7	4.8	%	$	186.7	$	621.2	27.9	%	$	485.8
Net Income	1.8		5.9	%	1.7		5.5		3.8	%	5.3

Third Quarter and Year to Date

Operating revenues and net income increased due to higher sales volume and higher market prices. 

Other Operating Expenses

Other operating expenses were as follows:

	Third Quarter						Year to Date
Millions of dollars	2013		Change		2012		2013		Change		2012
Other operation and maintenance	$	166.6	1.1	%	$	164.8	$	513.5	0.7	%	$	509.7
Depreciation and amortization	94.6		6.7	%	88.7		282.4		5.9	%	266.6
Other taxes	54.4		7.3	%	50.7		163.7		4.7	%	156.3

33

Third Quarter

Other operation and maintenance expenses increased by $4.5 million due to incremental expenses authorized in the December 2012 rate order. These increases were partially offset by $1.5 million due to lower compensation and by lower other general expenses. Depreciation and amortization expense increased $3.3 million due to the recognition of depreciation expense associated with the Wateree Station scrubber which was provided for in the December 2012 rate order and due to other net plant additions.  Other taxes increased primarily due to higher property taxes on net property additions.

Year to Date

Other operation and maintenance expenses increased by $12.7 million due to incremental expenses authorized in the December 2012 rate order. These increases were partially offset by $1.3 million due to lower generation expenses, by $7.7 million due to lower compensation and by lower other general expenses. Depreciation and amortization expense increased $9.9 million due to the recognition of depreciation expense associated with the Wateree Station scrubber which was provided for in the December 2012 rate order and due to other net plant additions.  Other taxes increased primarily due to higher property taxes on net property additions.

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.  AFC increased in 2013 due to higher 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, 2013 were higher than the same periods in 2012 primarily due to higher income. The increase in the effective tax rate in 2013 is principally attributable to lower recognition of EIZ Credits upon the completion of the amortization of certain such credits in 2012.

LIQUIDITY AND CAPITAL RESOURCES

The Company anticipates that its cash obligations will be met through internally generated funds, the incurrence of additional short- and long-term indebtedness and sales of equity securities.  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, 2013 was 3.28 and 3.19, 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 Branch Banking and Trust Company.  These letters of credit expire, subject to renewal, in the fourth quarter of 2014.

At September 30, 2013, the Company had net available liquidity of approximately $1.4 billion. The term of each of the Company's credit agreements was extended by one year in October 2013. 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 2018. 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 18 years and bears an average interest cost of 5.7%.  Substantially 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.

34

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, bankers, 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 $150 million outstanding with maturity dates of one year or less. The authority described herein will expire in October 2014.

SCANA issued approximately $76 million of stock during the nine months ended September 30, 2013 through various compensation and dividend reinvestment plans.  Similar issuances are expected in future periods. In addition, on March 5, 2013, SCANA settled all forward sales contracts related to its common stock through the issuance of approximately 6.6 million common shares, resulting in net proceeds of approximately $196 million.

On May 28, 2013, Standard & Poor's Ratings Services revised the rating outlook of SCANA, SCE&G and PSNC Energy to "negative" from "stable" but affirmed the corporate credit ratings for each of these entities.

In connection with the expected delays in the substantial completion of the New Units described in Note 9 to the condensed consolidated financial statements, SCE&G's current preliminary estimates of its capital expenditures for new nuclear construction (including transmission) for 2013 through 2015, which are subject to continuing review and adjustment, are $680 million in 2013, $897 million in 2014, and $839 million in 2015.

OTHER MATTERS

Retail Gas Marketing

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. In the third quarter, the GPSC voted to extend the current two year term for SCANA Energy by one year to August 31, 2015.

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 - The Company's market risk exposures relative to interest rate risk have not changed materially compared with the Company's Annual Report on Form 10-K for the year ended December 31, 2012. Interest rates on substantially all of the Company's outstanding long-term debt, other than credit facility draws, 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, see ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – LIQUIDITY AND CAPITAL RESOURCES and also Notes 4 and 6 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.  The SCPSC authorized the suspension of SCE&G's natural gas hedging program in January 2012. The fair value of SCE&G's derivative instruments remaining to be settled were not significant for any period presented. See Note 6 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.

35

	Expected Maturity			Expected Maturity
Futures - Long	2013	2014	Options Purchased Call - Long	2013	2014
Settlement Price (a)	3.65	3.83	Strike Price (a)	4.02	4.01
Contract Amount (b)	5.4	11.0	Contract Amount (b)	12.9	26.4
Fair Value (b)	5.1	10.6	Fair Value (b)	0.1	1.2
(a)  Weighted average, in dollars
(b)  Millions of dollars

	Expected Maturity
Swaps	2013	2014	2015	2016	2017
Commodity Swaps:
Pay fixed/receive variable (b)	22.9	52.1	16.0	9.3	0.5
Average pay rate (a)	4.1463	4.2437	4.9717	4.7749	4.2850
Average received rate (a)	3.6581	3.8363	4.0615	4.1643	4.3014
Fair value (b)	20.2	47.1	13.1	8.1	0.5
Pay variable/receive fixed (b)	8.9	29.1	12.6	8.2	0.5
Average pay rate (a)	3.6484	3.8437	4.0631	4.1655	4.3014
Average received rate (a)	4.1780	4.3626	5.0156	4.7721	4.2900
Fair value (b)	10.2	33.0	15.6	9.4	0.5
Basis Swaps:
Pay variable/receive variable (b)	1.0	1.1	0.5	—	—
Average pay rate (a)	3.6666	3.9055	4.2019	—	—
Average received rate (a)	3.6425	3.8817	4.1804	—	—
Fair value (b)	1.0	1.1	0.5	—	—
(a) Weighted average, in dollars
(b) Millions of dollars

ITEM 4. CONTROLS AND PROCEDURES

As of September 30, 2013, 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, 2013, 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, 2013 that has materially affected or is reasonably likely to materially affect SCANA’s internal control over financial reporting.

36

SOUTH CAROLINA ELECTRIC & GAS COMPANY

FINANCIAL SECTION

37

ITEM 1.     FINANCIAL STATEMENTS

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

Millions of dollars	September 30, 2013			December 31, 2012
Assets
Utility Plant In Service	$	10,310		$	10,096
Accumulated Depreciation and Amortization	(3,456		)	(3,322		)
Construction Work in Progress	2,521			2,073
Plant to be Retired, Net	344			362
Nuclear Fuel, Net of Accumulated Amortization	296			166
Utility Plant, Net ($708 and $640 related to VIEs)	10,015			9,375
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	68			57
Assets held in trust, net - nuclear decommissioning	98			94
Other investments	2			3
Nonutility Property and Investments, Net	168			154
Current Assets:
Cash and cash equivalents	17			51
Receivables, net of allowance for uncollectible accounts of $3 and $3	523			483
Affiliated receivables	20			2
Inventories (at average cost):
Fuel and gas supply	161			204
Materials and supplies	130			126
Prepayments and other	164			143
Total Current Assets ($162 and $206 related to VIEs)	1,015			1,009
Deferred Debits and Other Assets:
Regulatory assets	1,259			1,377
Other	237			189
Total Deferred Debits and Other Assets ($43 and $54 related to VIEs)	1,496			1,566
Total	$	12,694		$	12,104

38

Millions of dollars	September 30, 2013		December 31, 2012
Capitalization and Liabilities
Common equity	$	4,336	$	3,929
Noncontrolling interest	117		114
Long-Term Debt, net	4,043		3,557
Total Capitalization	8,496		7,600
Current Liabilities:
Short-term borrowings	310		449
Current portion of long-term debt	14		165
Accounts Payable	210		281
Affiliated Payables	122		124
Customer deposits and customer prepayments	53		51
Taxes accrued	158		151
Interest accrued	53		63
Dividends declared	67		46
Derivative financial instruments	2		66
Other	41		50
Total Current Liabilities	1,030		1,446
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,529		1,479
Deferred investment tax credits	33		36
Asset retirement obligations	549		535
Postretirement benefits	198		254
Regulatory liabilities	781		665
Other	78		89
Total Deferred Credits and Other Liabilities	3,168		3,058
Commitments and Contingencies (Note 9)	—		—
Total	$	12,694	$	12,104

See Notes to Condensed Consolidated Financial Statements.

39

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited) 

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Millions of dollars	2013			2012			2013			2012
Operating Revenues:
Electric	$	706		$	716		$	1,903		$	1,857
Gas	70			61			297			244
Total Operating Revenues	776			777			2,200			2,101
Operating Expenses:
Fuel used in electric generation	197			240			575			622
Purchased power	19			9			34			20
Gas purchased for resale	45			38			177			134
Other operation and maintenance	132			130			406			402
Depreciation and amortization	78			73			234			220
Other taxes	50			46			149			142
Total Operating Expenses	521			536			1,575			1,540
Operating Income	255			241			625			561
Other Expense:				156,311
Other expense	(4		)	(3		)	(11		)	(9		)
Interest charges, net of allowance for borrowed funds used during construction of $4, $3, $9 and $7	(54		)	(53		)	(163		)	(157		)
Allowance for equity funds used during construction	8			5			18			12
Total Other Expense	(50		)	(51		)	(156		)	(154		)
Income Before Income Tax Expense	205			190			469			407
Income Tax Expense	66			58			150			126
Net Income	139			132			319			281
Net Income Attributable to Noncontrolling Interest	(3		)	(3		)	(8		)	(9		)
Earnings Available to Common Shareholder	$	136		$	129		$	311		$	272
Dividends Declared on Common Stock	$	67		$	56		$	195		$	163

See Notes to Condensed Consolidated Financial Statements.

40

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	2013			2012			2013			2012
Net Income	$	139		$	132		$	319		$	281
Other Comprehensive Income, net of tax:
Employee benefit plan remeasurement and curtailment gains arising during the period, net of tax of $-, $-, $- and $-	1			—			1			—
Total Comprehensive Income	140			132			320			281
Comprehensive income attributable to noncontrolling interest	(3		)	(3		)	(8		)	(9		)
Comprehensive income available to common shareholder	$	137		$	129		$	312		$	272

Accumulated other comprehensive loss totaled $2.7 million as of September 30, 2013 and $4.0 million as of December 31, 2012.

See Notes to Condensed Consolidated Financial Statements.

41

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
Millions of dollars	2013			2012
Cash Flows From Operating Activities:
Net income	$	319		$	281
Adjustments to reconcile net income to net cash provided from operating activities:
Deferred income taxes, net	49			74
Depreciation and amortization	237			221
Amortization of nuclear fuel	42			38
Allowance for equity funds used during construction	(18		)	(12		)
Changes in certain assets and liabilities:
Receivables	(58		)	(22		)
Inventories	5			(49		)
Prepayments and other	(51		)	(57		)
Regulatory assets	129			(1		)
Regulatory liabilities	80			49
Accounts payable	(7		)	13
Taxes accrued	7			(8		)
Interest accrued	(10		)	(1		)
Postretirement benefits	(117		)	—
Other assets	(30		)	47
Other liabilities	(3		)	(20		)
Net Cash Provided From Operating Activities	574			553
Cash Flows From Investing Activities:
Property additions and construction expenditures	(794		)	(793		)
Proceeds from investments (including derivative collateral posted)	139			196
Purchase of investments (including derivative collateral posted)	(112		)	(199		)
Payments upon interest rate contract settlement	(49		)	—
Proceeds from interest rate contract settlement	43			14
Net Cash Used For Investing Activities	(773		)	(782		)
Cash Flows From Financing Activities:
Proceeds from issuance of long-term debt	451			517
Repayment of long-term debt	(248		)	(13		)
Dividends	(174		)	(146		)
Contributions from parent	285			84
Short-term borrowings –affiliate, net	(10		)	(9		)
Short-term borrowings, net	(139		)	(185		)
Net Cash Provided From Financing Activities	165			248
Net Decrease In Cash and Cash Equivalents	(34		)	19
Cash and Cash Equivalents, January 1	51			16
Cash and Cash Equivalents, September 30	$	17		$	35
Supplemental Cash Flow Information:
Cash paid for– Interest (net of capitalized interest of $9 and $7)	$	160		$	147
– Income taxes	67			81
Noncash Investing and Financing Activities:
Accrued construction expenditures	89			66
Capital leases	3			4
Nuclear fuel purchase	98			—

See Notes to Condensed Consolidated Financial Statements.

42

SOUTH CAROLINA ELECTRIC & GAS COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

For the Three and Nine Months Ended September 30, 2013 and 2012

(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, 2012.  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 is the primary beneficiary of 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 $478 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

In 2012, SCE&G announced its intention to retire six coal-fired units by 2018, subject to future developments in environmental regulations, among other matters. These units had an aggregate generating capacity (summer 2012) of 730 MW. One of these units (90 MW) was retired in 2012 and its net carrying value is recorded in regulatory assets as unrecovered plant (see Note 2). In June 2013, SCE&G approved a plan to accelerate the retirement of two more of these units (295 MW) by the end of 2013, and in the third quarter SCE&G received SCPSC approval to record the net carrying value of these units in regulatory assets as unrecovered plant once they are retired and to amortize such costs over the units' previously estimated remaining useful lives. The net carrying value of the remaining units to be retired (including these two units) is included in Plant to be Retired, Net in the consolidated financial statements. In connection with their retirement, SCE&G expects to be allowed a recovery of and a return on the net carrying value of the remaining units through rates. In the meantime, these units remain in rate base, and SCE&G continues to depreciate them using composite straight-line rates approved by the SCPSC.

43

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. In April 2012, the SCPSC approved SCE&G's request to decrease the total fuel cost component of its retail electric rates, and approved a settlement agreement among SCE&G, the ORS and SCEUC in which SCE&G agreed to recover an amount equal to its under-collected balance of base fuel and variable environmental costs as of April 30, 2012, or $80.6 million, over a 12-month period beginning with the first billing cycle of May 2012.

This April 2012 order was superseded, in part, by a December 2012 rate order in which the SCPSC authorized SCE&G to reduce the base fuel cost component of its retail electric rates and, in doing so, stated that SCE&G may not adjust its base fuel cost component prior to the last billing cycle of April 2014, except where necessary due to extraordinary unforeseen economic or financial conditions.  In February 2013, in connection with its annual review of base rates for fuel costs, SCE&G requested authorization to reduce its environmental fuel cost component effective with the first billing cycle of May 2013.  Consistent with the December 2012 rate order,SCE&G did not request any adjustment to its base fuel cost component.  On March 14, 2013, SCE&G, ORS and the SCEUC entered into a settlement agreement accepting the proposed lower environmental fuel cost component effective with the first billing cycle of May 2013, and providing for the accrual of certain debt-related carrying costs on a portion of the undercollected balance of fuel costs. The SCPSC issued an order dated April 30, 2013, adopting and approving the settlement agreement and approving SCE&G's total fuel cost component.

Electric - Base Rates

On December 19, 2012, the SCPSC approved a 4.23% overall increase in SCE&G's retail electric base rates, effective January 1, 2013, and authorized an allowed return on common equity of 10.25%. The SCPSC also approved a mid-period reduction to the cost of fuel component in rates (as discussed above), a reduction in the DSM Programs component rider to retail rates, and the recovery of and a return on the net carrying value of certain retired generating plant assets described below. By order dated February 7, 2013, the SCPSC denied the SCEUC's petition for rehearing of this order and the order was not appealed.

The eWNA is designed to mitigate the effects of abnormal weather on residential and commercial customers' bills and is based on a 15 year historical average of temperatures. In connection with the December 2012 rate order, SCE&G agreed to perform a study of alternative structures for the eWNA. The study was completed and filed with the SCPSC on June 28, 2013. In the study, SCE&G proposed that no adjustment or modification to the eWNA be made at this time.  On November 1, 2013, the ORS filed a report with the SCPSC recommending that the eWNA be terminated with the last billing cycle for December 2013. SCE&G will be working with the ORS to address its recommendation. SCE&G cannot predict what action the SCPSC may take, if any.

In February 2013, SCE&G filed an IRP with the SCPSC. The IRP evaluates future electric generation needs based on a variety of factors, including customer energy demands, EPA regulations, reserve margins and fuel costs. The IRP identified a total of six coal-fired units that SCE&G retired or intends to retire by 2018, subject to future developments in environmental regulations, among other matters. One of these units was retired in 2012, and its net carrying value is recorded in regulatory assets as unrecovered plant and is being amortized over its previously estimated remaining useful life. The net carrying value of the remaining units is included in Plant to be Retired, Net in the consolidated financial statements. In connection with their retirement, SCE&G expects to be allowed a recovery of and a return on the net carrying value of these remaining units through rates. In the meantime, these units remain in rate base, and SCE&G continues to depreciate them using composite straight-line rates approved by the SCPSC. As discussed in Note 1, SCE&G approved a plan to accelerate the retirement of two of the units by the end of 2013 and has received SCPSC approval to record the net carrying value of these units in regulatory assets as unrecovered plant once they are retired.

SCE&G's DSM Programs for electric customers provide for an annual rider, approved by the SCPSC, to allow recovery of the costs and net lost revenue associated with the DSM Programs, along with an incentive for investing in such programs. SCE&G submits annual filings regarding the DSM Programs, net lost revenues, program costs, incentives and net program benefits. The SCPSC has approved the following rate changes pursuant to annual DSM Programs filings, which changes became effective as indicated:

44

Year	Effective	Amount
2013	First billing cycle of May	$16.9 million
2012	First billing cycle of May	$19.6 million

In addition, the SCPSC approved the deferral of an additional $10.3 million of net lost revenues and provided for their recovery over a 12-month period beginning with the first billing cycle in May 2014.

SCE&G's initial authorization to operate its DSM Programs expires November 30, 2013. On May 31, 2013, SCE&G filed a request with the SCPSC for approval to extend the operation of its portfolio of DSM Programs.  SCE&G also requested approval to continue the use of the annual rate rider which (i) maintains the same terms and conditions currently in effect for the recovery of costs associated with the proposed DSM Programs, the net lost revenue associated with its DSM Programs, and an appropriate incentive for investing in such programs, and (ii) modifies the opt-out requirements for industrial customers.  SCE&G requested that the proposed DSM Programs and rate rider authorization be effective December 1, 2013.

 On October 21, 2013, SCE&G entered into a Settlement Agreement with ORS, Wal-Mart Stores East, LP, Sam’s East, Inc. and the SCEUC.  Under the Settlement Agreement, the settling parties agreed that SCE&G’s revised portfolio of DSM Programs should be approved as filed by SCE&G.  As for the annual rate rider, the settling parties agreed that SCE&G should be allowed to (i) continue to defer and amortize all prudently incurred costs for the DSM Programs over five years with carrying costs, (ii) calculate the net lost revenues component of the DSM Programs rider utilizing a rolling three year period of program history, and (iii) continue to recover a shared savings incentive, among other things.  The settling parties also agreed that SCE&G’s DSM Programs should continue for six years. Two other parties in the case did not execute the Settlement Agreement.  A public hearing on this matter was held on October 24, 2013, and the SCPSC's ruling is pending.

Electric – BLRA

In November 2012, the SCPSC approved an updated construction schedule and additional updated capital costs of $278 million (SCE&G's portion in 2007 dollars). The November 2012 order approved additional identifiable capital costs of approximately $1 million (SCE&G's portion in 2007 dollars) related to new federal healthcare laws, information security measures, and certain minor design modifications; approximately $8 million (SCE&G's portion in 2007 dollars) related to transmission infrastructure; and approximately $132 million (SCE&G's portion in 2007 dollars) related to additional labor for the oversight of the New Units during construction and for preparing to operate the New Units, and facilities and information technology systems required to support the New Units and their personnel. In addition, the order approved revised substantial completion dates for the New Units based on the March 30, 2012 issuance of the COL and the amounts agreed upon by SCE&G and the Consortium in July 2012 to resolve claims for costs related to COL delays, design modifications of the shield building and certain pre-fabricated structural modules for the New Units and unanticipated rock conditions at the site. Thereafter, two parties filed separate petitions requesting that the SCPSC reconsider its November 2012 order. On December 12, 2012, the SCPSC denied both petitions. In March 2013, both parties appealed the SCPSC's order to the South Carolina Supreme Court. SCE&G is unable to predict the outcome of these appeals. For further discussion of new nuclear construction matters, see Note 9.

Under the BLRA, SCE&G is allowed to 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. Requested rate adjustments are 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 the following rate changes under the BLRA effective for bills rendered on and after October 30 in the years indicated:

Year	Action			Amount
2013	2.9	%	Increase	$67.2 million
2012	2.3	%	Increase	$52.1 million

Gas

The RSA is designed to reduce the volatility of costs charged to customers by allowing for 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 years indicated:

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Year	Action			Amount
2013	No change			-
2012	2.1	%	Increase	$7.5 million

On June 5, 2013, SCE&G submitted its annual RSA filing with the SCPSC for the 12-month period ending March 31, 2013. SCE&G earned a return on its gas distribution operations, after proforma adjustments, that is within the range of its allowable rate of return on common equity. The SCPSC approved SCE&G’s annual RSA filing on October 9, 2013, with no change in rates.

SCE&G's natural gas tariffs include a PGA clause that provides for the recovery of actual gas costs incurred. 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. The 2012 annual PGA hearing to review SCE&G's gas purchasing policies and procedures was held in November 2012 before the SCPSC. The SCPSC issued an order in December 2012 finding that SCE&G's gas purchasing policies and practices during the review period of August 1, 2011 through July 31, 2012, were reasonable and prudent. SCE&G’s 2013 annual PGA hearing was held on November 7, 2013, and the SCPSC's ruling 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 time periods than do enterprises that are not rate-regulated.  As a result, Consolidated SCE&G has recorded regulatory assets and regulatory liabilities, which are summarized in the following tables.  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, 2013		December 31, 2012
Regulatory Assets:
Accumulated deferred income taxes	$	248	$	248
Under collections – electric fuel adjustment clause	52		66
Environmental remediation costs	37		39
AROs and related funding	342		304
Franchise agreements	32		36
Deferred employee benefit plan costs	284		405
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	126		151
Deferred pollution control costs	37		38
Unrecovered plant	19		20
Other	82		64
Total Regulatory Assets	$	1,259	$	1,377

Regulatory Liabilities:
Accumulated deferred income taxes	$	19	$	21
Asset removal costs	522		507
Storm damage reserve	27		27
Deferred gains on interest rate derivatives	203		110
Planned major maintenance	10		—
Total Regulatory Liabilities	$	781	$	665

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 70 years.  Similarly, accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability.

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Under-collections - electric fuel adjustment clause represent amounts due from customers pursuant to the fuel adjustment clause as approved by the SCPSC during annual hearings which are not expected to be recovered in retail electric rates within 12 months. 

Environmental remediation costs represent costs associated with the assessment and clean-up of MGP sites currently or formerly owned by SCE&G.  These regulatory assets are expected to be recovered over periods of up to approximately 26 years.

ARO and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station and conditional AROs.  These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 90 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 began amortizing these amounts through cost of service rates in February 2003 over approximately 20 years.

Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under generally accepted accounting principles. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. In connection with the December 2012 rate order, approximately $63 million of deferred pension costs for electric operations are to be recovered through utility rates over approximately 30 years. In connection with the October 2013 RSA order, approximately $14 million of deferred pension costs for gas operations are to be recovered through utility rates 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 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, as approved pursuant to specific SCPSC orders.  SCE&G collects $18.4 million annually for fossil fueled turbine/generation equipment maintenance.  Through December 31, 2012, nuclear refueling charges were accrued during each 18-month refueling outage cycle as a component of cost of service. In connection with the December 2012 rate order, effective January 1, 2013, SCE&G began to collect and accrue $17.2 million annually for nuclear-related refueling charges.

Deferred losses or gains on interest rate derivatives generally represent unrealized losses or gains from fair value adjustments and payments made or received upon termination of certain interest rate derivatives.  These amounts are expected to be amortized to interest expense over the lives of the underlying debt, up to approximately 30 years, unless, in the case of gains, such amounts are applied otherwise at the direction of regulators.

Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the scrubbers installed at Wateree and Williams Stations pursuant to specific regulatory orders.  Such costs are being recovered through utility rates over periods up to approximately 30 years. 

Unrecovered plant represents the net book value of a coal-fired generating unit retired from service prior to being fully depreciated. Pursuant to the December 2012 rate order, SCE&G is amortizing these amounts over the unit's previously estimated remaining useful life of approximately 14 years. Unamortized amounts are included in rate base.

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.

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 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

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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, 2013 and 2012 were as follows:

Millions of dollars	Common Equity			Noncontrolling Interest			Total Equity
Balance at January 1, 2013	$	3,929		$	114		$	4,043
Capital contribution from parent	285			—			285
Dividends declared	(190		)	(5		)	(195		)
Comprehensive income	312			8			320
Balance as of September 30, 2013	$	4,336		$	117		$	4,453
Balance at January 1, 2012	$	3,665		$	108		$	3,773
Capital contribution from parent	84			—			84
Dividends declared	(157		)	(5		)	(162		)
Comprehensive income	272			9			281
Balance as of September 30, 2012	$	3,864		$	112		$	3,976

SCE&G had 50 million shares of common stock authorized as of September 30, 2013 and December 31, 2012, of which 40.3 million were issued and outstanding during all periods presented. SCE&G had 20 million shares of preferred stock authorized as of September 30, 2013 and December 31, 2012, of which 1,000 shares 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 June 2013, SCE&G issued $400 million of 4.60% first mortgage bonds due June 15, 2043. Proceeds from this sale were used to pay at maturity $150 million of its 7.125% first mortgage bonds due June 15, 2013, 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 January 2013, JEDA issued at a premium, for the benefit of SCE&G, $39.5 million of 4.0% tax-exempt industrial revenue bonds due February 1, 2028, and $14.7 million of 3.63% tax-exempt industrial revenue bonds due February 1, 2033. Proceeds from these sales were loaned by JEDA to SCE&G and, together with other available funds, were used to redeem prior to maturity $56.9 million of 5.2% industrial revenue bonds due November 1, 2027.

 Substantially all of Consolidated SCE&G’s electric utility plant is pledged as collateral in connection with long-term debt. Consolidated SCE&G is in compliance with all debt covenants.

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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, 2013			December 31, 2012
Lines of credit:
Total committed long-term	$	1,400		$	1,400
LOC advances	—			—
Weighted average interest rate	—			—
Outstanding commercial paper (270 or fewer days)	$	310		$	449
Weighted average interest rate	0.30		%	0.42		%
Letters of credit supported by LOC	$	0.3		$	0.3
Available	$	1,090		$	951

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). In addition, SCE&G is party to a three-year credit agreement in the amount of $200 million. In October 2013, the term of each of these credit agreements was extended by one year, such that the five-year agreements will expire in October 2018, and the three-year agreement 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 Branch Banking and Trust Company.  The letters of credit expire, subject to renewal, in the fourth quarter of 2014.

Consolidated SCE&G participates in a utility money pool. Money pool borrowings and investments bear interest at short-term market rates. Consolidated SCE&G’s interest income and expense from money pool transactions was not significant for any period presented. At September 30, 2013 and December 31, 2012, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $39.6 million and $49.4 million, respectively.

5. INCOME TAXES

No material changes in the status of Consolidated SCE&G's tax positions have occurred through September 30, 2013.

During the third quarter of 2013, the IRS issued final regulations regarding the capitalization of certain costs for income tax purposes and re-proposed certain other related regulations (collectively referred to as tangible personal property regulations). These regulations did not have a material impact on Consolidated SCE&G's financial position, results of operations or cash flows.

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 the 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 the Audit Committee’s 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 lock or forward starting swap agreements that are designated as cash flow hedges.  Except as described in the following paragraph, the effective portions of changes in fair value and payments made or received upon termination of such agreements are recorded in regulatory assets or regulatory liabilities.  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 authorization granted in October 2013, certain interest rate derivatives entered into by SCE&G will no longer be designated as cash flow hedges, and fair value changes and settlement amounts are to be recorded in its regulatory asset and liability accounts. Upon settlement, losses on swaps will be amortized over the lives of related debt issuances, and gains may be applied to undercollected fuel amounts or may be amortized to interest expense as 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

Consolidated SCE&G was a party to interest rate swaps designated as cash flow hedges with an aggregate notional amount of $571.4 million at September 30, 2013 and $971.4 million at December 31, 2012.

The fair value of interest rate derivatives was reflected in the condensed consolidated balance sheet as follows:

	Fair Values of Derivative Instruments
	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
Millions of dollars	Location	Value		Location	Value
As of September 30, 2013
Derivatives designated as hedging instruments
Interest rate	Prepayments and other	$	83	Other current liabilities	$	2
	Other deferred debits and other assets	41		Other deferred credits and other liabilities	1
Total		$	124		$	3
As of December 31, 2012
Derivatives designated as hedging instruments
Interest rate	Prepayments and other	$	42	Other current liabilities	$	66
	Other deferred debits and other assets	31		Other deferred credits and other liabilities	9
Total		$	73		$	75

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

Derivatives in Cash Flow Hedging Relationships	Gain Deferred in Regulatory Accounts					Loss Reclassified from Deferred Accounts into Income
	(Effective Portion)					(Effective Portion)
Millions of dollars	2013		2012		Location	2013			2012
Three Months Ended September 30,
Interest rate	$	19	$	23	Interest expense	$	(1	)	$	(1	)
Nine Months Ended September 30,
Interest rate	$	115	$	51	Interest expense	$	(2	)	$	(2	)

Derivatives not designated as Hedging Instruments		Loss Recognized in Income
Millions of dollars	Location	2013	2012
Three Months Ended September 30,
Commodity	Gas purchased for resale	—	—
Nine Months Ended September 30,
Commodity	Gas purchased for resale	—	$	(1	)

Hedge Ineffectiveness

Other gains (losses) recognized in income representing ineffectiveness on interest rate hedges designated as cash flow hedges were insignificant in each of the three and nine months ended September 30, 2013 and 2012, respectively.

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 on an ongoing basis. 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, 2013 and December 31, 2012, Consolidated SCE&G has posted $3.3 million and $35.2 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 Prepayments and other on the consolidated balance sheets. Collateral related to noncurrent positions is recorded in Other within Deferred Debits and Other Assets on the consolidated balance sheets. If all of the contingent features underlying these instruments had been fully triggered as of September 30, 2013 and December 31, 2012, Consolidated SCE&G could have been required to post an additional $- million and $22.7 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, 2013 and December 31, 2012 is $2.6 million and $57.9 million, respectively.

In addition, as of September 30, 2013 and December 31, 2012, 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 were fully triggered as of September 30, 2013 and December 31, 2012, Consolidated SCE&G could request $78.6 million and $32.1 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, 2013 and December 31, 2012 is $78.6 million and $32.1 million, respectively.

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

						Gross Amounts Not Offset in the Statement of Financial Position
Millions of dollars	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Financial Instruments			Cash Collateral Received	Net Amount
As of September 30, 2013
Interest rate	$	124	—	$	124	$	(3	)	—	$	121
Balance Sheet Location	Prepayments and other			$	83
	Other deferred debits and other assets			41
	Total			$	124

As of December 31, 2012
Interest rate	$	73	—	$	73	$	(17	)	—	$	56
Balance Sheet Location	Prepayments and other			$	42
	Other deferred debits and other assets			31
	Total			$	73

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

						Gross Amounts Not Offset in the Statement of Financial Position
Millions of dollars	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Financial Instruments			Cash Collateral Posted		Net Amount
As of September 30, 2013
Interest rate	$	3	—	$	3	$	(3	)	$	—	$	—
Balance Sheet Location	Other current liabilities			$	2
	Other deferred credits and other liabilities			1
	Total			$	3

As of December 31, 2012
Interest rate	$	75	—	$	75	$	(17	)	$	(35	)	$	23
Balance Sheet Location	Other current liabilities			$	66
	Other deferred credits and other liabilities			9
	Total			$	75

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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 measurements based on significant other observable inputs (level 2) were as follows: 

		Fair Value Measurements Using Significant
		Other Observable Inputs (Level 2)
Millions of dollars		September 30, 2013		December 31, 2012
Assets -	Interest rate contracts	$	124	$	73
Liabilities -	Interest rate contracts	3		75

There were no fair value measurements based on quoted prices in active markets for identical assets (Level 1) or significant unobservable inputs (Level 3) for either period presented.  In addition, 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 at September 30, 2013 and December 31, 2012 were as follows:

	September 30, 2013				December 31, 2012
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	4,056.4	$	4,454.4	$	3,722.0	$	4,543.1

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

Pension and Other Postretirement Benefit Plans

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

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2013			2012			2013		2012
Three months ended September 30,
Service cost	$	4.1		$	4.1		$	1.0	$	0.8
Interest cost	8.0			9.1			2.1		2.3
Expected return on assets	(12.7		)	(12.6		)	—		—
Prior service cost amortization	1.3			1.6			0.1		0.1
Charge due to curtailment	8.4			—			—		—
Amortization of actuarial losses	3.0			3.7			0.7		0.1
Net periodic benefit cost	$	12.1		$	5.9		$	3.9	$	3.3

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Nine months ended September 30,
Service cost	$	13.7		$	11.8		$	3.5	$	2.8
Interest cost	24.0			27.3			6.5		7.0
Expected return on assets	(38.7		)	(37.8		)	—		—
Prior service cost amortization	4.1			4.5			0.4		0.5
Charge due to curtailment	8.4			—			—		—
Amortization of actuarial losses	12.2			11.7			2.0		0.3
Net periodic benefit cost	$	23.7		$	17.5		$	12.4	$	10.6

No significant contribution to the pension trust is expected until after 2016, nor is a limitation on benefits payments expected to apply. As authorized by the SCPSC, prior to January 1, 2013 SCE&G deferred all pension expense related to retail electric and gas operations as a regulatory asset. In connection with the SCPSC's December 2012 rate order, effective January 1, 2013 SCE&G began recovering current pension expense related to retail electric operations through a rate rider that is adjusted annually.SCE&G also began recovering previously deferred pension expense as described in Note 2.Costs totaling $1.2 million and $2.4 million related to gas operations were deferred for the three and nine months ended September 30, 2013, respectively. Costs totaling $4.0 million and $11.4 million related to electric and gas operations were deferred for the corresponding periods in 2012. In connection with the October 2013 RSA order, beginning in November 2013, SCE&G will begin recovering current pension expense related to gas operations through cost of service rates and will begin recovering previously deferred costs as described in Note 2.

In the third quarter 2013, SCANA amended its pension plan, such that pension benefits will no longer be offered to employees hired or rehired after December 31, 2013, and pension benefits for existing participants will no longer accrue for services performed or compensation earned after December 31, 2023.  As a result, SCE&G recorded a curtailment charge due to the accelerated amortization of prior service cost. Approximately $5.4 million of the curtailment charge was applicable to regulated operations and was deferred within regulatory assets. SCE&G expects to recover such deferred amounts through existing regulatory orders or to request recovery in future proceedings.

In connection with the pension plan amendment, SCANA remeasured its pension obligation in the third quarter of 2013 using current assumptions for the discount rate and future salary increases. The pension plan amendment and remeasurement resulted in a reduction in SCE&G's pension obligation of approximately $108 million.

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 the Company's nuclear power plant. Price-Anderson provides funds up to $13.6 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 $40.6 million.

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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 or other cost and expenses, 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.

Environmental

As part of the President's Climate Action Plan and by Presidential Memorandum issued June 25, 2013, the EPA was directed to issue a revised carbon standard for new power plants by September 20, 2013, to be made final as soon as appropriate. Standards, regulations, or guidelines are also required for existing units by June 1, 2014, to be made final no later than June 1, 2015. On September 20, 2013, EPA re-proposed NSPS under the CAA for emissions of carbon dioxide from newly constructed fossil fuel-fired units. Consolidated SCE&G is evaluating the proposed rule, but cannot predict when it will become final, if at all, or what conditions it may impose on the Company, if any. Consolidated SCE&G also cannot predict when rules will become final for existing units, if at all, or what conditions they may impose on Consolidated SCE&G, if any. Consolidated SCE&G expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates.

In 2005, the EPA issued the CAIR, which required the District of Columbia and 28 states to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels.  CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for nitrogen oxide and beginning in 2010 and 2015, respectively, for sulfur dioxide.  SCE&G and GENCO determined that additional air quality controls would be needed to meet the CAIR requirements. On July 6, 2011 the EPA issued the CSAPR.  This rule replaced CAIR and the Clean Air Transport Rule proposed in July 2010 and is aimed at addressing power plant emissions that may contribute to air pollution in other states.  CSAPR requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide.  On December 30, 2011, the United States Court of Appeals for the District of Columbia issued an order staying CSAPR and reinstating CAIR pending resolution of an appeal of CSAPR. On August 21, 2012, the Court of Appeals vacated CSAPR and left CAIR in place. The EPA's petition for rehearing of the Court of Appeals' order was denied. In June, 2013, the U.S. Supreme Court agreed to review the Court of Appeals' decision and has scheduled oral arguments for December 10, 2013. Air quality control installations that SCE&G and GENCO have already completed have allowed Consolidated SCE&G to comply with the reinstated CAIR.  Consolidated SCE&G will continue to pursue strategies to comply with all applicable environmental regulations.  Any costs incurred to comply with such regulations are expected to be recoverable through rates.

In April 2012, the EPA's rule containing new standards for mercury and other specified air pollutants became effective.  The rule provides up to four years for facilities to meet the standards, and Consolidated SCE&G's evaluation of the rule is ongoing. Consolidated SCE&G's decision in 2012 to retire certain coal-fired units or convert them to burn natural gas and its project to build the New Units (see Note 1) along with other actions are expected to result in Consolidated SCE&G's compliance with the EPA's rule.  Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates.

The EPA is conducting an enforcement initiative against the utilities industry related to the NSR provisions and the NSPS of the CAA. As part of the initiative, many utilities have received requests for information under Section 114 of the CAA. In addition, the DOJ, on behalf of the EPA, has taken civil enforcement action against several utilities. The primary basis for these actions is the assertion by the EPA that maintenance activities undertaken by the utilities at their coal-fired power plants constituted “major modifications” which required the installation of costly BACT. Some of the utilities subject to the actions have reached settlement. Though Consolidated SCE&G cannot predict what action, if any, the EPA will initiate against it, any costs incurred are expected to be recoverable through rates.

Consolidated SCE&G maintains an environmental assessment program to identify and evaluate its current and former operations sites that could require environmental clean-up.  As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site.  Environmental liabilities are accrued when the criteria for loss contingencies are met. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates.  Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations.  Amounts expected to be recovered through rates are recorded in regulatory assets and, if applicable, amortized over approved amortization periods. Other environmental costs are recorded to expense.

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SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of byproduct 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 until 2017 and will cost an additional $21.2 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, 2013, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $37.1 million and are included in regulatory assets.

New Nuclear Construction

SCE&G, on behalf of itself and as agent for Santee Cooper, has contracted with the Consortium for the design and construction of the New Units at the site of Summer Station.  SCE&G's share of the estimated cash outlays (future value, excluding AFC) totals approximately $5.7 billion for plant and related transmission infrastructure costs, and is projected based on historical one-year and five-year escalation rates as required by the SCPSC.

The Consortium has experienced delays in the schedule for fabrication and delivery of sub-modules for the New Units. The fabrication and delivery of sub-modules are a focus area of the Consortium. The delivery schedule of sub-modules for structural module CA20, which is part of the auxiliary building, and CA01, which houses components inside the containment vessel, is now expected to support completion of on-site fabrication to allow them to be set on the nuclear island for the first New Unit during the first and third quarters of 2014, respectively. With this schedule, the Consortium continues to indicate that the substantial completion of the first New Unit is expected to be late 2017 or the first quarter of 2018 and that the substantial completion of the second New Unit is expected to be approximately twelve months after that of the first New Unit. The substantial completion dates currently approved by the SCPSC for the first and second New Units are March 15, 2017 and May 15, 2018, respectively. The SCPSC has also approved an 18-month contingency period beyond each of these dates. The preliminary expected new substantial completion dates are within the contingency periods. SCE&G cannot predict with certainty the extent to which the issue with the sub-modules or the delays in the substantial completion of the New Units will result in increased project costs. However, the preliminary estimate of the delay-related costs associated with SCE&G's share of the New Units is approximately $200 million. SCE&G has not accepted responsibility for any of these delay-related costs and expects to have further discussions with the Consortium regarding such responsibility. Additionally, the EPC Contract provides for liquidated damages in the event of a delay in the completion of the facility, which will also be included in discussions with the Consortium. SCE&G believes its responsibility for any portion of the $200 million estimate should ultimately be substantially less, once all of the relevant factors are considered.

In addition to the above-described project delays, SCE&G is also aware of financial difficulties at a supplier responsible for certain significant components of the project.  The Consortium is monitoring the potential for disruptions in such equipment fabrication and possible responses.   Any disruptions could impact the project's schedule or costs, and such impacts could be material.

Subject to a national megawatt capacity limitation, the electricity to be produced by the New Units (advanced nuclear units, as defined) is expected to qualify for nuclear production tax credits under Section 45J of the Internal Revenue Code. Following the pouring of safety-related concrete for each of the Units’ reactor buildings (March 2013 for the first New Unit and November 2013 for the second New Unit), the Company has applied to the IRS for its allocations of such national megawatt capacity limitation. The IRS will forward the applications to the United States Department of Energy for appropriate certification.

The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve issues that arise during the course of constructing a project of this magnitude.  During the course of activities under the EPC Contract, issues have materialized that impact project budget and schedule. Claims specifically relating to COL delays,

design modifications of the shield building and certain pre-fabricated modules for the New Units and unanticipated rock

conditions at the site resulted in assertions of contractual entitlement to recover additional costs to be incurred. The resolution

of these specific claims is discussed in Note 2. SCE&G expects to resolve any disputes that arise in the future, including any which may arise with respect to the delay-related costs discussed above, through both the informal and formal procedures and anticipates that any additional costs that arise through such dispute resolution processes, as well as other costs identified from time to time, will be recoverable through rates.

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, as well as a request for

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information related to emergency plant staffing.  These conditions and requirements are responsive to the NRC's Near-Term Task Force report titled “Recommendations for Enhancing Reactor Safety in the 21st Century.”  This report was prepared in the wake of the March 2011 earthquake-generated tsunami, which severely damaged several nuclear generating units and their back-up cooling systems in Japan. SCE&G continues to evaluate the impact of these conditions and requirements that may be imposed on the construction and operation of the New Units, and SCE&G prepared and submitted an integrated response plan for the New Units to the NRC in August 2013.  SCE&G cannot predict what additional regulatory or other outcomes may be implemented in the United States, or how such initiatives would impact SCE&G's existing Summer Station or the construction or operation of the New Units.

SCE&G understands that Santee Cooper continues to evaluate reduction of its level of participation in the New Units through potential sales of portions of its interest therein to third parties. SCE&G is unable to predict whether any change in Santee Cooper's ownership interest or the addition of new joint owners will increase project costs or delay the substantial completion dates of the New Units.  Any such project cost increase or delay could be material.

10. AFFILIATED TRANSACTIONS

CGT transports natural gas to SCE&G to serve SCE&G’s retail gas customers and certain electric generation requirements.  Transportation services totaled approximately $25.3 million and $27.1 million for the nine months ended September 30, 2013 and 2012, respectively.  SCE&G had approximately $3.0 million and $3.4 million payable to CGT for transportation services at September 30, 2013 and December 31, 2012, respectively.

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 $132.7 million and $84.0 million for the nine months ended September 30, 2013 and 2012, respectively.  SCE&G’s payables to SEMI for such purposes were $13.2 million and $13.1 million as of September 30, 2013 and December 31, 2012, respectively.

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 owned 10% of Cope Refined Coal, LLC through December 31, 2012. SCE&G accounts for these investments using the equity method.  SCE&G’s receivables from these affiliates were $19.7 million at September 30, 2013 and $1.8 million at December 31, 2012.  SCE&G’s payables to these affiliates were $19.8 million at September 30, 2013 and $1.8 million at December 31, 2012.  SCE&G’s total purchases from these affiliates were $73.7 million and $87.3 million for the nine months ended September 30, 2013 and 2012, respectively.  SCE&G’s total sales to these affiliates were $73.4 million and $86.9 million for the nine months ended September 30, 2013 and 2012, respectively.

Consolidated SCE&G receives the following services from SCANA Services and its parent company, which are rendered at direct or allocated cost: information systems 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. Consolidated SCE&G’s payables for such purposes were $40.3 million and $45.8 million as of September 30, 2013 and December 31, 2012, respectively.

Money pool borrowings from an affiliate are described at 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.

	External		Operating			Earnings Available to
Millions of dollars	Revenue		Income			Common Shareholder
Three Months Ended September 30, 2013
Electric Operations	$	706	$	257		n/a
Gas Distribution	70		(2		)	n/a
Adjustments/Eliminations	—		—			$	136
Consolidated Total	$	776	$	255		$	136

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Nine Months Ended September 30, 2013
Electric Operations	$	1,903	$	588	n/a
Gas Distribution	297		37		n/a
Adjustments/Eliminations	—		—		$	311
Consolidated Total	$	2,200	$	625	$	311

Three Months Ended September 30, 2012
Electric Operations	$	716	$	244		n/a
Gas Distribution	61		(3		)	n/a
Adjustments/Eliminations	—		—			$	129
Consolidated Total	$	777	$	241		$	129

Nine Months Ended September 30, 2012
Electric Operations	$	1,857	$	534	n/a
Gas Distribution	244		27		n/a
Adjustments/Eliminations	—		—		$	272
Consolidated Total	$	2,101	$	561	$	272

	September 30,		December 31,
Segment Assets	2013		2012
Electric Operations	$	9,430	$	8,989
Gas Distribution	681		659
Adjustments/Eliminations	2,583		2,456
Consolidated Total	$	12,694	$	12,104

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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, 2012. 

RESULTS OF OPERATIONS

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2013

AS COMPARED TO THE CORRESPONDING PERIODS IN 2012

Net Income

Net income for Consolidated SCE&G was as follows:

	Third Quarter						Year to Date
Millions of dollars	2013		Change		2012		2013		Change		2012
Net income	$	139.3	5.4	%	$	132.2	$	319.1	13.4	%	$	281.5

Third Quarter and Year to Date

Net income increased due to higher electric and gas margins.  These margin increases were partially offset by higher operation and maintenance expenses, higher depreciation expense and higher property 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 2013:

Declaration Date	Amount	Quarter Ended	Payment Date
February 20, 2013	$64.0 million	March 31, 2013	April 1, 2013
April 25, 2013	$63.8 million	June 30, 2013	July 1, 2013
July 31, 2013	$67.5 million	September 30, 2013	October 1, 2013
October 31, 2013	$61.7 million	December 31, 2013	January 1, 2014

Electric Operations

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

	Third Quarter						Year to Date
Millions of dollars	2013		Change		2012		2013		Change		2012
Operating revenues	$	706.0	(1.4	)%	$	716.2	$	1,903.2	2.5	%	$	1,857.6
Less: Fuel used in generation	197.6		(17.7	)%	240.0		574.5		(7.6	)%	621.9
Purchased power	18.9		*		9.4		34.7		76.1	%	19.7
Margin	$	489.5	4.9	%	$	466.8	$	1,294.0	6.4	%	$	1,216.0

* Greater than 100%

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Third Quarter

Electric margin increased primarily due to base rate increases under the BLRA of $15.5 million and higher retail electric base rates of $21.5 million approved in the December 2012 rate order.

Year to Date

Electric margin increased primarily due to base rate increases under the BLRA of $40.7 million and higher retail electric base rates of $53.5 million approved in the December 2012 rate order.

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

	Third Quarter				Year to Date
Classification	2013	Change		2012	2013	Change		2012
Residential	2,216	(6.6	)%	2,372	5,858	(0.1	)%	5,861
Commercial	2,073	(2.8	)%	2,132	5,520	(1.8	)%	5,622
Industrial	1,584	3.5	%	1,531	4,505	1.7	%	4,430
Other	164	(1.8	)%	167	442	(1.6	)%	449
Total Retail Sales	6,037	(2.7	)%	6,202	16,325	(0.2	)%	16,362
Wholesale	245	(63.8	)%	677	736	(62.0	)%	1,935
Total Sales	6,282	(8.7	)%	6,879	17,061	(6.8	)%	18,297

Third Quarter 

Retail sales volume decreased primarily due to weather and lower average use, partially offset by customer growth. The decrease in wholesale sales is primarily due to the expiration of two customer contracts.

Year to Date

Retail sales volume decreased primarily due to lower average use, partially offset by customer growth and the effects of weather. The decrease in wholesale sales is primarily due to the expiration of two customer contracts.

Gas Distribution

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

	Third Quarter						Year to Date
Millions of dollars	2013		Change		2012		2013		Change		2012
Operating revenues	$	70.1	14.0	%	$	61.5	$	297.0	21.8	%	$	243.9
Less: Gas purchased for resale	45.1		19.9	%	37.6		176.8		32.0	%	133.9
Margin	$	25.0	4.6	%	$	23.9	$	120.2	9.3	%	$	110.0

Third Quarter and Year to Date

Margin increased primarily due to the SCPSC-approved increase in base rates under the RSA which became effective with the first billing cycle of November 2012, as well as residential and commercial customer growth.

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Sales volumes (in MMBTU) by class, including transportation, were as follows: 

	Third Quarter				Year to Date
Classification (in thousands)	2013	Change		2012	2013	Change		2012
Residential	681	5.1	%	648	8,400	36.4	%	6,159
Commercial	2,307	5.4	%	2,188	9,245	12.3	%	8,230
Industrial	4,857	6.7	%	4,554	15,307	9.2	%	14,021
Transportation	1,079	2.3	%	1,055	3,527	1.6	%	3,471
Total	8,924	5.7	%	8,445	36,479	14.4	%	31,881

Third Quarter and Year to Date

Total sales volumes increased primarily due to customer growth and industrial usage. For year to date, the increase is also due to the effects of weather.

Other Operating Expenses

Other operating expenses were as follows:

	Third Quarter						Year to Date
Millions of dollars	2013		Change		2012		2013		Change		2012
Other operation and maintenance	$	132.1	1.5	%	$	130.1	$	405.8	0.9	%	$	402.2
Depreciation and amortization	78.3		7.3	%	73.0		234.5		6.7	%	219.8
Other taxes	49.7		7.1	%	46.4		148.8		4.6	%	142.2

Third Quarter

Other operation and maintenance expenses increased by $4.5 million due to incremental expenses authorized in the December 2012 rate order. These increases were partially offset by $2.3 million due to lower compensation and by lower other general expenses. Depreciation and amortization expense increased $3.3 million due to the recognition of depreciation expense associated with the Wateree Station scrubber which was provided for in the December 2012 rate order and due to net plant additions.  Other taxes increased primarily due to higher property taxes on net property additions.

Year to Date

Other operation and maintenance expenses increased by $12.7 million due to incremental expenses authorized in the December 2012 rate order. These increases were partially offset by $1.3 million due to lower generation expenses, by $5.7 million due to lower compensation and by lower other general expenses. Depreciation and amortization expense increased $9.9 million due to the recognition of depreciation expense associated with the Wateree Station scrubber which was provided for in the December 2012 rate order and due to net plant additions.  Other taxes increased primarily due to higher property taxes on net property additions.

Other 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.  AFC increased in 2013 due to higher AFC rates.

Interest Expense

Interest charges increased primarily due to increased borrowings.

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Income Taxes

Income taxes for the three and nine months ended September 30, 2013 were higher than the same periods in 2012 primarily due to higher income. The increase in the effective tax rate in 2013 is principally attributable to lower recognition of EIZ Credits upon the completion of amortization of certain such credits in 2012.

LIQUIDITY AND CAPITAL RESOURCES

Consolidated SCE&G anticipates that its cash obligations will be met through internally generated funds, the incurrence of additional short- and long-term indebtedness, 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, 2013 was 3.69 and 3.46, respectively.

SCE&G received approximately $285 million during the nine months ended September 30, 2013 as an equity contribution from its parent company.

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 Branch Banking and Trust Company.  These letters of credit expire, subject to renewal, in the fourth quarter of 2014.

At September 30, 2013, Consolidated SCE&G had net available liquidity of approximately $1.1 billion. The term of Consolidated SCE&G's credit agreements was extended in October 2013. 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 2018. 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 20 years and bears an average interest cost of 5.7%.  Substantially 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, bankers, 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 $150 million outstanding with maturity dates of one year or less. The authority described herein will expire in October 2014.

On May 28, 2013, Standard & Poor's Ratings Services revised the rating outlook of SCE&G to "negative" from "stable" but affirmed SCE&G’s corporate credit rating.

In connection with the expected delays in the substantial completion of the New Units described in Note 9 to the condensed consolidated financial statements, SCE&G's current preliminary estimates of its capital expenditures for new nuclear construction (including transmission) for 2013 through 2015, which are subject to continuing review and adjustment, are $680 million in 2013, $897 million in 2014, and $839 million in 2015.

OTHER MATTERS

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 - Consolidated SCE&G's market risk exposures relative to interest rate risk have not changed materially compared with SCE&G's Annual Report on Form 10-K for the year ended December 31, 2012. Interest rates on substantially all of Consolidated SCE&G's outstanding long-term debt, other than credit facility draws, are fixed either through the issuance of fixed rate debt or through the use of interest rate derivatives. Consolidated SCE&G is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near future.

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For further discussion of changes in long-term debt and interest rate derivatives, see ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - LIQUIDITY AND CAPITAL RESOURCES and also Notes 4 and 6 of the condensed consolidated financial statements.

ITEM 4. CONTROLS AND PROCEDURES

As of September 30, 2013, 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, 2013, 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, 2013, that has materially affected or is reasonably likely to materially affect SCE&G’s internal control over financial reporting.

PART II.  OTHER INFORMATION

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 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 a link to the New Nuclear Development section of the website.  That section in turn contains a yellow box with a link to project news and updates.  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, and investors, media and others interested in SCE&G’s new nuclear project are encouraged to review this information.

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 8, 2013		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)
4.01		X	Third Supplemental Indenture to Indenture dated as of April 1, 1993 from SCE&G to The Bank of New York Mellon Trust Company, N. A. (as successor to NationsBank of Georgia, National Association), as Trustee, dated as of September 1, 2013 (Filed as Exhibit 4.12 to Post-Effective Amendment to Registration Statement No. 333-184426-01 and incorporated by reference herein)
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 Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
32.02	X		Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
32.03		X	Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
32.04		X	Certification of 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.

62

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 8, 2013
	/s/Kevin B. Marsh
	Kevin B. Marsh
	Chairman of the Board, President, Chief Executive Officer and
	Chief Operating Officer

65

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 8, 2013
	/s/Jimmy E. Addison
	Jimmy E. Addison
	Executive Vice President and Chief Financial Officer

66

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 8, 2013
	/s/Kevin B. Marsh
	Kevin B. Marsh
	Chairman of the Board and Chief Executive Officer

67

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 8, 2013
	/s/Jimmy E. Addison
	Jimmy E. Addison
	Executive Vice President and Chief Financial Officer

68

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, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I 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 8, 2013

/s/Kevin B. Marsh

Kevin B. Marsh

Chairman of the Board, President, Chief Executive Officer

and Chief Operating Officer

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request. 

69

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 SCANA Corporation (the “Company”) on Form 10-Q for the quarter ended September 30, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I 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 8, 2013

/s/Jimmy E. Addison

Jimmy E. Addison

Executive Vice President and Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request. 

70

EX-32.03

Exhibit 32.03

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, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I 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 8, 2013

/s/Kevin B. Marsh

Kevin B. Marsh

Chairman of the Board and Chief Executive Officer

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request. 

71

EX-32.04

Exhibit 32.04

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, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I 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 8, 2013

/s/Jimmy E. Addison

Jimmy E. Addison

Executive Vice President and Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request. 

72

XML

EMPLOYEE BENEFIT PLANS

9 Months Ended

Sep. 30, 2013

Pension and Other Postretirement Benefit Plans

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS

Pension and Other Postretirement Benefit Plans

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

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2013			2012			2013		2012
Three months ended September 30,
Service cost	$	5.1		$	5.0		$	1.2	$	1.1
Interest cost	9.5			10.9			2.8		2.9
Expected return on assets	(15.1		)	(15.0		)	—		—
Prior service cost amortization	1.5			1.8			0.1		0.2
Charge due to curtailment	9.9			—			—		—
Transition obligation amortization	—			—			—		0.2
Amortization of actuarial losses	3.5			4.5			0.8		—
Net periodic benefit cost	$	14.4		$	7.2		$	4.9	$	4.4

Nine months ended September 30,
Service cost	$	16.9		$	14.7		$	4.4	$	3.6
Interest cost	28.4			32.2			8.3		8.9
Expected return on assets	(45.8		)	(44.6		)	—		—
Prior service cost amortization	4.9			5.3			0.5		0.7
Charge due to curtailment	9.9			—			—		—
Transition obligation amortization	—			—			0.3		0.5
Amortization of actuarial losses	14.4			13.8			2.5		0.4
Net periodic benefit cost	$	28.7		$	21.4		$	16.0	$	14.1

No significant contribution to the pension trust is expected until after 2016, nor is a limitation on benefits payments expected to apply. As authorized by the SCPSC, prior to January 1, 2013 SCE&G deferred all pension expense related to retail electric and gas operations as a regulatory asset. In connection with the SCPSC's December 2012 rate order, effective January 1, 2013 SCE&G began recovering current pension expense related to retail electric operations through a rate rider that is adjusted annually. SCE&G also began recovering previously deferred pension expense as described in Note 2. Costs totaling $1.2 million and $2.4 million related to gas operations were deferred for the three and nine months ended September 30, 2013, respectively. Costs totaling $4.0 million and $11.4 million related to electric and gas operations were deferred for the corresponding periods in 2012. In connection with the October 2013 RSA order, beginning in November 2013, SCE&G will begin recovering current pension expense related to gas operations through cost of service rates and will begin recovering previously deferred costs as described in Note 2.

In the third quarter 2013, the Company amended its pension plan, such that pension benefits will no longer be offered to employees hired or rehired after December 31, 2013, and pension benefits for existing participants will no longer accrue for services performed or compensation earned after December 31, 2023.  As a result, the Company recorded a curtailment charge due to the accelerated amortization of prior service cost. Approximately $6.3 million of the curtailment charge was applicable to regulated operations and was deferred within regulatory assets. The Company expects to recover such deferred amounts through existing regulatory orders or to request recovery in future proceedings.

In connection with the pension plan amendment, the Company remeasured its pension obligation in the third quarter of 2013 using current assumptions for the discount rate and future salary increases. The pension plan amendment and remeasurement resulted in a reduction in the Company's pension obligation of approximately $128 million.

SCEG

Pension and Other Postretirement Benefit Plans

EMPLOYEE BENEFIT PLANS

Pension and Other Postretirement Benefit Plans

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

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2013			2012			2013		2012
Three months ended September 30,
Service cost	$	4.1		$	4.1		$	1.0	$	0.8
Interest cost	8.0			9.1			2.1		2.3
Expected return on assets	(12.7		)	(12.6		)	—		—
Prior service cost amortization	1.3			1.6			0.1		0.1
Charge due to curtailment	8.4			—			—		—
Amortization of actuarial losses	3.0			3.7			0.7		0.1
Net periodic benefit cost	$	12.1		$	5.9		$	3.9	$	3.3

Nine months ended September 30,
Service cost	$	13.7		$	11.8		$	3.5	$	2.8
Interest cost	24.0			27.3			6.5		7.0
Expected return on assets	(38.7		)	(37.8		)	—		—
Prior service cost amortization	4.1			4.5			0.4		0.5
Charge due to curtailment	8.4			—			—		—
Amortization of actuarial losses	12.2			11.7			2.0		0.3
Net periodic benefit cost	$	23.7		$	17.5		$	12.4	$	10.6

No significant contribution to the pension trust is expected until after 2016, nor is a limitation on benefits payments expected to apply. As authorized by the SCPSC, prior to January 1, 2013 SCE&G deferred all pension expense related to retail electric and gas operations as a regulatory asset. In connection with the SCPSC's December 2012 rate order, effective January 1, 2013 SCE&G began recovering current pension expense related to retail electric operations through a rate rider that is adjusted annually.SCE&G also began recovering previously deferred pension expense as described in Note 2.Costs totaling $1.2 million and $2.4 million related to gas operations were deferred for the three and nine months ended September 30, 2013, respectively. Costs totaling $4.0 million and $11.4 million related to electric and gas operations were deferred for the corresponding periods in 2012. In connection with the October 2013 RSA order, beginning in November 2013, SCE&G will begin recovering current pension expense related to gas operations through cost of service rates and will begin recovering previously deferred costs as described in Note 2.

In the third quarter 2013, SCANA amended its pension plan, such that pension benefits will no longer be offered to employees hired or rehired after December 31, 2013, and pension benefits for existing participants will no longer accrue for services performed or compensation earned after December 31, 2023.  As a result, SCE&G recorded a curtailment charge due to the accelerated amortization of prior service cost. Approximately $5.4 million of the curtailment charge was applicable to regulated operations and was deferred within regulatory assets. SCE&G expects to recover such deferred amounts through existing regulatory orders or to request recovery in future proceedings.

In connection with the pension plan amendment, SCANA remeasured its pension obligation in the third quarter of 2013 using current assumptions for the discount rate and future salary increases. The pension plan amendment and remeasurement resulted in a reduction in SCE&G's pension obligation of approximately $108 million.

XML

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Operating Revenues:
Electric Domestic Regulated Revenue	$ 704	$ 714	$ 1,898	$ 1,851
Regulated Operating Revenue, Gas	128	109	667	513
Gas-nonregulated	219	215	813	690
Regulated and Unregulated Operating Revenue	1,051	1,038	3,378	3,054
Operating Expenses [Abstract]
Fuel used in electric generation	196	239	570	617
Purchased power	19	9	35	20
Gas purchased for resale	265	248	1,076	837
Other operation and maintenance	167	165	513	510
Depreciation and amortization	95	89	282	267
Other taxes	54	50	164	156
Total Operating Expenses	796	800	2,640	2,407
Operating Income	255	238	738	647
Other Income (Expense):
Interest Expense	(74)	(75)	(223)	(219)
Other income	10	13	36	39
Other expenses	(10)	(9)	(32)	(29)
Allowance for equity funds used during construction	9	6	19	13
Total Other Expense	(65)	(65)	(200)	(196)
Income Before Income Tax Expense	190	173	538	451
Income Tax Expense	59	51	170	136
Income Available to Common Shareholders	131	122	368	315
Per Common Share Data
Basic Earnings Per Share of Common Stock (in dollars per share)	$ 0.94	$ 0.93	$ 2.67	$ 2.41
Diluted Earnings Per Share of Common Stock (in dollars per share)	$ 0.94	$ 0.91	$ 2.66	$ 2.37
Weighted Average Common Shares Outstanding (millions)
Weighted Average Number of Shares Outstanding, Basic	140.1	131.4	138.0	130.8
Weighted Average Number of Shares Outstanding, Diluted	140.1	133.8	138.6	133.1
Dividends Declared Per Share of Common Stock (in dollars per share)	$ 0.5075	$ 0.495	$ 1.5225	$ 1.485
SCEG
Operating Revenues:
Electric Domestic Regulated Revenue	706	716	1,903	1,857
Regulated Operating Revenue, Gas	70	61	297	244
Regulated Operating Revenue	776	777	2,200	2,101
Operating Expenses [Abstract]
Fuel used in electric generation	197	240	575	622
Purchased power	19	9	34	20
Gas purchased for resale	45	38	177	134
Other operation and maintenance	132	130	406	402
Depreciation and amortization	78	73	234	220
Other taxes	50	46	149	142
Total Operating Expenses	521	536	1,575	1,540
Operating Income	255	241	625	561
Other Income (Expense):
Interest Expense	(54)	(53)	(163)	(157)
Other expenses	(4)	(3)	(11)	(9)
Allowance for equity funds used during construction	8	5	18	12
Total Other Expense	(50)	(51)	(156)	(154)
Income Before Income Tax Expense	205	190	469	407
Income Tax Expense	66	58	150	126
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	139	132	319	281
Net Income (Loss) Attributable to Noncontrolling Interest	(3)	(3)	(8)	(9)
Net Income (Loss) Attributable to Parent	136	129	311	272
Weighted Average Common Shares Outstanding (millions)
Dividends, Common Stock, Cash	$ 67	$ 56	$ 195	$ 163

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

9 Months Ended

Sep. 30, 2013

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

In 2012, SCE&G announced its intention to retire six coal-fired units by 2018, subject to future developments in environmental regulations, among other matters. These units had an aggregate generating capacity (summer 2012) of 730 MW. One of these units (90 MW) was retired in 2012 and its net carrying value is recorded in regulatory assets as unrecovered plant (see Note 2). In June 2013, SCE&G approved a plan to accelerate the retirement of two more of these units (295 MW) by the end of 2013, and in the third quarter SCE&G received SCPSC approval to record the net carrying value of these units in regulatory assets as unrecovered plant once they are retired and to amortize such costs over the units' previously estimated remaining useful lives. The net carrying value of the remaining units to be retired (including these two units) is included in Plant to be Retired, Net in the consolidated financial statements. In connection with their retirement, SCE&G expects to be allowed a recovery of and a return on the net carrying value of the remaining units through rates. In the meantime, these units remain in rate base, and SCE&G continues to depreciate them using composite straight-line rates approved by the SCPSC.

Earnings Per Share

The Company computes basic earnings per share by dividing net income by the weighted average number of common shares outstanding for the period.  The Company computes diluted earnings per share using this same formula after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method.  The Company has issued no securities that would have an antidilutive effect on earnings per share.

Reconciliations of the weighted average number of common shares for basic and diluted earnings per share computation purposes are as follows:     

	Third Quarter		Year to Date
Millions	2013	2012	2013	2012
Weighted Average Shares Outstanding - Basic	140.1	131.4	138.0	130.8
Effect of dilutive equity forward shares	—	2.4	0.6	2.3
Weighted Average Shares - Diluted	140.1	133.8	138.6	133.1

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 47% and 44% of PSNC Energy’s natural gas inventory at September 30, 2013

and December 31, 2012, respectively, with a carrying value of $23.2 million and $19.6 million, respectively, through either capacity release or agency relationships.  Under the terms of the asset management agreements, PSNC Energy receives storage asset management fees. The agreements expire March 31, 2015.

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 is the primary beneficiary of 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 $478 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

In 2012, SCE&G announced its intention to retire six coal-fired units by 2018, subject to future developments in environmental regulations, among other matters. These units had an aggregate generating capacity (summer 2012) of 730 MW. One of these units (90 MW) was retired in 2012 and its net carrying value is recorded in regulatory assets as unrecovered plant (see Note 2). In June 2013, SCE&G approved a plan to accelerate the retirement of two more of these units (295 MW) by the end of 2013, and in the third quarter SCE&G received SCPSC approval to record the net carrying value of these units in regulatory assets as unrecovered plant once they are retired and to amortize such costs over the units' previously estimated remaining useful lives. The net carrying value of the remaining units to be retired (including these two units) is included in Plant to be Retired, Net in the consolidated financial statements. In connection with their retirement, SCE&G expects to be allowed a recovery of and a return on the net carrying value of the remaining units through rates. In the meantime, these units remain in rate base, and SCE&G continues to depreciate them using composite straight-line rates approved by the SCPSC.

XML

COMMON EQUITY (Tables)

9 Months Ended

Sep. 30, 2013

Schedule of Capitalization, Equity [Line Items]

Schedule of Stockholders Equity [Table Text Block]

Changes in common equity during the nine months ended September 30, 2013 and 2012 were as follows:

Millions of dollars	2013			2012
Balance at January 1,	$	4,154		$	3,889
Common stock issued	273			73
Dividends declared	(212		)	(194		)
Comprehensive income	383			327
Balance as of September 30,	$	4,598		$	4,095

Reclassifications from Other Comprehensive Income [Table Text Block]

Reclassifications of gains (losses) from AOCI into earnings, net of taxes, were as follows:

Millions of dollars	2013			2012			Income Statement Line Item Affected
Three months ended September 30,
Interest rate contracts	$	(2	)	$	(2	)	Increase in interest expense
Commodity contracts	—			(1		)	Increase in gas purchased for resale
Deferred employee benefit plan costs	(1		)	—
Total reclassifications	$	(3	)	$	(3	)
Nine months ended September 30,
Interest rate contracts	$	(5	)	$	(5	)	Increase in interest expense
Commodity contracts	(2		)	(12		)	Increase in gas purchased for resale
Deferred employee benefit plan costs	(1		)	(1		)
Total reclassifications	$	(8	)	$	(18	)

For information related to the reclassification of deferred employee benefit amounts from AOCI, see Note 8.

SCEG

Schedule of Capitalization, Equity [Line Items]

Schedule of Stockholders Equity [Table Text Block]

Changes in common equity during the nine months ended September 30, 2013 and 2012 were as follows:

Millions of dollars	Common Equity			Noncontrolling Interest			Total Equity
Balance at January 1, 2013	$	3,929		$	114		$	4,043
Capital contribution from parent	285			—			285
Dividends declared	(190		)	(5		)	(195		)
Comprehensive income	312			8			320
Balance as of September 30, 2013	$	4,336		$	117		$	4,453
Balance at January 1, 2012	$	3,665		$	108		$	3,773
Capital contribution from parent	84			—			84
Dividends declared	(157		)	(5		)	(162		)
Comprehensive income	272			9			281
Balance as of September 30, 2012	$	3,864		$	112		$	3,976

XML

COMMITMENTS AND CONTINGENCIES

9 Months Ended

Sep. 30, 2013

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 the Company's nuclear power plant. Price-Anderson provides funds up to $13.6 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 $40.6 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 or other costs and expenses, 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.

Environmental

As part of the President's Climate Action Plan and by Presidential Memorandum issued June 25, 2013, the EPA was directed to issue a revised carbon standard for new power plants by September 20, 2013, to be made final as soon as appropriate. Standards, regulations, or guidelines are also required for existing units by June 1, 2014, to be made final no later than June 1, 2015. On September 20, 2013, EPA re-proposed NSPS under the CAA for emissions of carbon dioxide from newly constructed fossil fuel-fired units.The Company is evaluating the proposed rule, but cannot predict when it will become final, if at all, or what conditions it may impose on the Company, if any. The Company also cannot predict when rules will become final for existing units, if at all, or what conditions they may impose on the Company, if any. The Company expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates.

In 2005, the EPA issued the CAIR, which required the District of Columbia and 28 states to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels.  CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for nitrogen oxide and beginning in 2010 and 2015, respectively, for sulfur dioxide.  SCE&G and GENCO determined that additional air quality controls would be needed to meet the CAIR requirements.  On July 6, 2011 the EPA issued the CSAPR.  This rule replaced CAIR and the Clean Air Transport Rule proposed in July 2010 and is aimed at addressing power plant emissions that may contribute to air pollution in other states.  CSAPR requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide.  On December 30, 2011, the United States Court of Appeals for the District of Columbia issued an order staying CSAPR and reinstating CAIR pending resolution of an appeal of CSAPR. On August 21, 2012, the Court of Appeals vacated CSAPR and left CAIR in place. The EPA's petition for rehearing of the Court of Appeals' order was denied. In June, 2013, the U.S. Supreme Court agreed to review the Court of Appeals' decision and has scheduled oral arguments for December 10, 2013. Air quality control installations that SCE&G and GENCO have already completed have allowed the Company to comply with the reinstated CAIR. The Company will continue to pursue strategies to comply with all applicable environmental regulations.  Any costs incurred to comply with such regulations are expected to be recoverable through rates.

In April 2012, the EPA's rule containing new standards for mercury and other specified air pollutants became effective.  The rule provides up to four years for facilities to meet the standards, and the Company's evaluation of the rule is ongoing. The Company's decision in 2012 to retire certain coal-fired units or convert them to burn natural gas and its project to build the New Units (see Note 1) along with other actions are expected to result in the Company's compliance with the EPA's rule.  Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates.

The EPA is conducting an enforcement initiative against the utilities industry related to the NSR provisions and the NSPS of the CAA. As part of the initiative, many utilities have received requests for information under Section 114 of the CAA. In addition, the DOJ, on behalf of the EPA, has taken civil enforcement action against several utilities. The primary basis for these actions is the assertion by the EPA that maintenance activities undertaken by the utilities at their coal-fired power plants constituted “major modifications” which required the installation of costly BACT. Some of the utilities subject to the actions have reached settlement. Though the Company cannot predict what action, if any, the EPA will initiate against it, any costs incurred are expected to be recoverable through rates.

The Company maintains an environmental assessment program to identify and evaluate its current and former operations sites that could require environmental clean-up.  As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site.  Environmental liabilities are accrued when the criteria for loss contingencies are met. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates.  Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations.  Amounts expected to be recovered through rates are recorded in regulatory assets and, if applicable, amortized over approved amortization periods. Other environmental costs are recorded to expense.

SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of byproduct 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 until 2017 and will cost an additional $21.2 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, 2013, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $37.1 million and are included in regulatory assets.

PSNC Energy is responsible for environmental clean-up at five sites in North Carolina on which MGP residuals are present or suspected.  PSNC Energy’s actual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other PRPs.  PSNC Energy has recorded a liability and associated regulatory asset of approximately $2.9 million, the estimated remaining liability at September 30, 2013. PSNC Energy expects to recover through rates any cost allocable to PSNC Energy arising from the remediation of these sites.

New Nuclear Construction

SCE&G, on behalf of itself and as agent for Santee Cooper, has contracted with the Consortium for the design and construction of the New Units at the site of Summer Station.  SCE&G's share of the estimated cash outlays (future value, excluding AFC) totals approximately $5.7 billion for plant and related transmission infrastructure costs, and is projected based on historical one-year and five-year escalation rates as required by the SCPSC.

The Consortium has experienced delays in the schedule for fabrication and delivery of sub-modules for the New Units. The fabrication and delivery of sub-modules are a focus area of the Consortium. The delivery schedule of sub-modules for structural module CA20, which is part of the auxiliary building, and CA01, which houses components inside the containment vessel, is now expected to support completion of on-site fabrication to allow them to be set on the nuclear island to the first New Unit during the first and third quarters of 2014, respectively. With this schedule, the Consortium continues to indicate that the substantial completion of the first New Unit is expected to be late 2017 or the first quarter of 2018 and that the substantial completion of the second New Unit is expected to be approximately twelve months after that of the first New Unit. The substantial completion dates currently approved by the SCPSC for the first and second New Units are March 15, 2017 and May 15, 2018, respectively. The SCPSC has also approved an 18-month contingency period beyond each of these dates. The preliminary expected new substantial completion dates are within the contingency periods. SCE&G cannot predict with certainty the extent to which the issue with the sub-modules or the delays in the substantial completion of the New Units will result in increased project costs. However, the preliminary estimate of the delay-related costs associated with SCE&G's share of the New Units is approximately $200 million. SCE&G has not accepted responsibility for any of these delay-related costs and expects to have further discussions with the Consortium regarding such responsibility. Additionally, the EPC Contract provides for liquidated damages in the event of a delay in the completion of the facility, which will also be included in discussions with the Consortium. SCE&G believes its responsibility for any portion of the $200 million estimate should ultimately be substantially less, once all of the relevant factors are considered.

In addition to the above-described project delays, SCE&G is also aware of financial difficulties at a supplier responsible for certain significant components of the project.  The Consortium is monitoring the potential for disruptions in such equipment fabrication and possible responses.   Any disruptions could impact the project's schedule or costs, and such impacts could be material.

Subject to a national megawatt capacity limitation, the electricity to be produced by the New Units (advanced nuclear units, as defined) is expected to qualify for nuclear production tax credits under Section 45J of the Internal Revenue Code. Following the pouring of safety-related concrete for each of the Units’ reactor buildings (March 2013 for the first New Unit and November 2013 for the second New Unit), the Company has applied to the IRS for its allocations of such national megawatt capacity limitation. The IRS will forward the applications to the United States Department of Energy for appropriate certification.

The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve issues that arise during the course of constructing a project of this magnitude.  During the course of activities under the EPC Contract, issues have materialized that impact project budget and schedule. Claims specifically relating to COL delays,

design modifications of the shield building and certain pre-fabricated modules for the New Units and unanticipated rock

conditions at the site resulted in assertions of contractual entitlement to recover additional costs to be incurred. The resolution

of these specific claims is discussed in Note 2. SCE&G expects to resolve any disputes that arise in the future, including any which may arise with respect to the delay-related costs discussed above, through both the informal and formal procedures and anticipates that any additional costs that arise through such dispute resolution processes, as well as other costs identified from time to time, will be recoverable through rates.

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, as well as a request for information related to emergency plant staffing.  These conditions and requirements are responsive to the NRC's Near-Term Task Force report titled “Recommendations for Enhancing Reactor Safety in the 21st Century.”  This report was prepared in the wake of the March 2011 earthquake-generated tsunami, which severely damaged several nuclear generating units and their back-up cooling systems in Japan.  SCE&G continues to evaluate the impact of these conditions and requirements that may be imposed on the construction and operation of the New Units, and SCE&G prepared and submitted an integrated response plan for the New Units to the NRC in August 2013.  SCE&G cannot predict what additional regulatory or other outcomes may be implemented in the United States, or how such initiatives would impact SCE&G's existing Summer Station or the construction or operation of the New Units.

SCE&G understands that Santee Cooper continues to evaluate reduction of its level of participation in the New Units through potential sales of portions of its interest therein to third parties. SCE&G is unable to predict whether any change in Santee Cooper's ownership interest or the addition of new joint owners will increase project costs or delay the substantial completion dates of the New Units.  Any such project cost increase or delay could be material.

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 the Company's nuclear power plant. Price-Anderson provides funds up to $13.6 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 $40.6 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 or other cost and expenses, 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.

Environmental

As part of the President's Climate Action Plan and by Presidential Memorandum issued June 25, 2013, the EPA was directed to issue a revised carbon standard for new power plants by September 20, 2013, to be made final as soon as appropriate. Standards, regulations, or guidelines are also required for existing units by June 1, 2014, to be made final no later than June 1, 2015. On September 20, 2013, EPA re-proposed NSPS under the CAA for emissions of carbon dioxide from newly constructed fossil fuel-fired units. Consolidated SCE&G is evaluating the proposed rule, but cannot predict when it will become final, if at all, or what conditions it may impose on the Company, if any. Consolidated SCE&G also cannot predict when rules will become final for existing units, if at all, or what conditions they may impose on Consolidated SCE&G, if any. Consolidated SCE&G expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates.

In 2005, the EPA issued the CAIR, which required the District of Columbia and 28 states to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels.  CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for nitrogen oxide and beginning in 2010 and 2015, respectively, for sulfur dioxide.  SCE&G and GENCO determined that additional air quality controls would be needed to meet the CAIR requirements. On July 6, 2011 the EPA issued the CSAPR.  This rule replaced CAIR and the Clean Air Transport Rule proposed in July 2010 and is aimed at addressing power plant emissions that may contribute to air pollution in other states.  CSAPR requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide.  On December 30, 2011, the United States Court of Appeals for the District of Columbia issued an order staying CSAPR and reinstating CAIR pending resolution of an appeal of CSAPR. On August 21, 2012, the Court of Appeals vacated CSAPR and left CAIR in place. The EPA's petition for rehearing of the Court of Appeals' order was denied. In June, 2013, the U.S. Supreme Court agreed to review the Court of Appeals' decision and has scheduled oral arguments for December 10, 2013. Air quality control installations that SCE&G and GENCO have already completed have allowed Consolidated SCE&G to comply with the reinstated CAIR.  Consolidated SCE&G will continue to pursue strategies to comply with all applicable environmental regulations.  Any costs incurred to comply with such regulations are expected to be recoverable through rates.

In April 2012, the EPA's rule containing new standards for mercury and other specified air pollutants became effective.  The rule provides up to four years for facilities to meet the standards, and Consolidated SCE&G's evaluation of the rule is ongoing. Consolidated SCE&G's decision in 2012 to retire certain coal-fired units or convert them to burn natural gas and its project to build the New Units (see Note 1) along with other actions are expected to result in Consolidated SCE&G's compliance with the EPA's rule.  Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates.

The EPA is conducting an enforcement initiative against the utilities industry related to the NSR provisions and the NSPS of the CAA. As part of the initiative, many utilities have received requests for information under Section 114 of the CAA. In addition, the DOJ, on behalf of the EPA, has taken civil enforcement action against several utilities. The primary basis for these actions is the assertion by the EPA that maintenance activities undertaken by the utilities at their coal-fired power plants constituted “major modifications” which required the installation of costly BACT. Some of the utilities subject to the actions have reached settlement. Though Consolidated SCE&G cannot predict what action, if any, the EPA will initiate against it, any costs incurred are expected to be recoverable through rates.

Consolidated SCE&G maintains an environmental assessment program to identify and evaluate its current and former operations sites that could require environmental clean-up.  As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site.  Environmental liabilities are accrued when the criteria for loss contingencies are met. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates.  Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations.  Amounts expected to be recovered through rates are recorded in regulatory assets and, if applicable, amortized over approved amortization periods. Other environmental costs are recorded to expense.

SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of byproduct 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 until 2017 and will cost an additional $21.2 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, 2013, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $37.1 million and are included in regulatory assets.

New Nuclear Construction

SCE&G, on behalf of itself and as agent for Santee Cooper, has contracted with the Consortium for the design and construction of the New Units at the site of Summer Station.  SCE&G's share of the estimated cash outlays (future value, excluding AFC) totals approximately $5.7 billion for plant and related transmission infrastructure costs, and is projected based on historical one-year and five-year escalation rates as required by the SCPSC.

The Consortium has experienced delays in the schedule for fabrication and delivery of sub-modules for the New Units. The fabrication and delivery of sub-modules are a focus area of the Consortium. The delivery schedule of sub-modules for structural module CA20, which is part of the auxiliary building, and CA01, which houses components inside the containment vessel, is now expected to support completion of on-site fabrication to allow them to be set on the nuclear island for the first New Unit during the first and third quarters of 2014, respectively. With this schedule, the Consortium continues to indicate that the substantial completion of the first New Unit is expected to be late 2017 or the first quarter of 2018 and that the substantial completion of the second New Unit is expected to be approximately twelve months after that of the first New Unit. The substantial completion dates currently approved by the SCPSC for the first and second New Units are March 15, 2017 and May 15, 2018, respectively. The SCPSC has also approved an 18-month contingency period beyond each of these dates. The preliminary expected new substantial completion dates are within the contingency periods. SCE&G cannot predict with certainty the extent to which the issue with the sub-modules or the delays in the substantial completion of the New Units will result in increased project costs. However, the preliminary estimate of the delay-related costs associated with SCE&G's share of the New Units is approximately $200 million. SCE&G has not accepted responsibility for any of these delay-related costs and expects to have further discussions with the Consortium regarding such responsibility. Additionally, the EPC Contract provides for liquidated damages in the event of a delay in the completion of the facility, which will also be included in discussions with the Consortium. SCE&G believes its responsibility for any portion of the $200 million estimate should ultimately be substantially less, once all of the relevant factors are considered.

In addition to the above-described project delays, SCE&G is also aware of financial difficulties at a supplier responsible for certain significant components of the project.  The Consortium is monitoring the potential for disruptions in such equipment fabrication and possible responses.   Any disruptions could impact the project's schedule or costs, and such impacts could be material.

Subject to a national megawatt capacity limitation, the electricity to be produced by the New Units (advanced nuclear units, as defined) is expected to qualify for nuclear production tax credits under Section 45J of the Internal Revenue Code. Following the pouring of safety-related concrete for each of the Units’ reactor buildings (March 2013 for the first New Unit and November 2013 for the second New Unit), the Company has applied to the IRS for its allocations of such national megawatt capacity limitation. The IRS will forward the applications to the United States Department of Energy for appropriate certification.

The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve issues that arise during the course of constructing a project of this magnitude.  During the course of activities under the EPC Contract, issues have materialized that impact project budget and schedule. Claims specifically relating to COL delays,

design modifications of the shield building and certain pre-fabricated modules for the New Units and unanticipated rock

conditions at the site resulted in assertions of contractual entitlement to recover additional costs to be incurred. The resolution

of these specific claims is discussed in Note 2. SCE&G expects to resolve any disputes that arise in the future, including any which may arise with respect to the delay-related costs discussed above, through both the informal and formal procedures and anticipates that any additional costs that arise through such dispute resolution processes, as well as other costs identified from time to time, will be recoverable through rates.

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, as well as a request for information related to emergency plant staffing.  These conditions and requirements are responsive to the NRC's Near-Term Task Force report titled “Recommendations for Enhancing Reactor Safety in the 21st Century.”  This report was prepared in the wake of the March 2011 earthquake-generated tsunami, which severely damaged several nuclear generating units and their back-up cooling systems in Japan. SCE&G continues to evaluate the impact of these conditions and requirements that may be imposed on the construction and operation of the New Units, and SCE&G prepared and submitted an integrated response plan for the New Units to the NRC in August 2013.  SCE&G cannot predict what additional regulatory or other outcomes may be implemented in the United States, or how such initiatives would impact SCE&G's existing Summer Station or the construction or operation of the New Units.

SCE&G understands that Santee Cooper continues to evaluate reduction of its level of participation in the New Units through potential sales of portions of its interest therein to third parties. SCE&G is unable to predict whether any change in Santee Cooper's ownership interest or the addition of new joint owners will increase project costs or delay the substantial completion dates of the New Units.  Any such project cost increase or delay could be material.

XML

DERIVATIVE FINANCIAL INSTRUMENTS (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013 MMBTU		Dec. 31, 2012 MMBTU
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	53,213,558	[1]	48,300,275	[2]
Nonmonetary Notional Amount of Basis Swap, Price Risk Derivative Instruments Not Designated as Hedging Instruments	674,308		3,500,000
Interest Rate Derivatives [Abstract]
Derivative, Notional Amount	$ 663.8		$ 1,100.0
Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	8,820,000		5,170,000
Retail Gas Marketing
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	10,407,000		6,490,000
Energy Marketing
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	33,986,558	[1]	36,640,275	[2]
Commodity Contract
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	22,305,500		16,537,000
Commodity Contract | Gas Distribution
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	8,820,000		5,170,000
Commodity Contract | Retail Gas Marketing
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	10,407,000		6,490,000
Commodity Contract | Energy Marketing
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	3,078,500		4,877,000
Energy Management Contracts [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	30,908,058		31,763,275
Energy Management Contracts [Member] | Energy Marketing
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	30,908,058		31,763,275
SCEG
Interest Rate Derivatives [Abstract]
Derivative, Notional Amount	$ 571.4		$ 971.4

[1] (a) Includes an aggregate 674,308 MMBTU related to basis swap contracts in Energy Marketing.

[2] (b) Includes an aggregate 3,500,000 MMBTU related to basis swap contracts in Energy Marketing.

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Tables)

9 Months Ended

Sep. 30, 2013

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Fair Value, Measurement Inputs, Disclosure [Table Text Block]

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

		Fair Value Measurements Using
		Quoted Prices in
		Active Markets for		Significant Other
		Identical Assets		Observable Inputs
Millions of dollars		(Level 1)		(Level 2)
As of September 30, 2013
Assets -	Available for sale securities	$	9	—
	Interest rate contracts	—		$	124
	Commodity contracts	1		—
	Energy management contracts	—		10
Liabilities -	Interest rate contracts	—		24
	Commodity contracts	—		3
	Energy management contracts	—		13
As of December 31, 2012
Assets -	Available for sale securities	$	6	—
	Interest rate contracts	—		$	73
	Commodity contracts	1		1
	Energy management contracts	—		13
Liabilities -	Interest rate contracts	—		106
	Commodity contracts	—		4
	Energy management contracts	1		15

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

Financial instruments for which the carrying amount may not equal estimated fair value at September 30, 2013 and December 31, 2012 were as follows:

	September 30, 2013				December 31, 2012
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	5,450.9	$	5,936.7	$	5,121.0	$	6,115.0

SCEG

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Fair Value, Measurement Inputs, Disclosure [Table Text Block]

Fair value measurements based on significant other observable inputs (level 2) were as follows: 

		Fair Value Measurements Using Significant
		Other Observable Inputs (Level 2)
Millions of dollars		September 30, 2013		December 31, 2012
Assets -	Interest rate contracts	$	124	$	73
Liabilities -	Interest rate contracts	3		75

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

Financial instruments for which the carrying amount may not equal estimated fair value at September 30, 2013 and December 31, 2012 were as follows:

	September 30, 2013				December 31, 2012
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	4,056.4	$	4,454.4	$	3,722.0	$	4,543.1

XML

DERIVATIVE FINANCIAL INSTRUMENTS (Tables)

9 Months Ended

Sep. 30, 2013

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, 2013
Commodity	8,820,000	10,407,000	3,078,500	22,305,500
Energy Management (a)	—	—	30,908,058	30,908,058
Total (a)	8,820,000	10,407,000	33,986,558	53,213,558
As of December 31, 2012
Commodity	5,170,000	6,490,000	4,877,000	16,537,000
Energy Management (b)	—	—	31,763,275	31,763,275
Total (b)	5,170,000	6,490,000	36,640,275	48,300,275

(a)  Includes an aggregate 674,308 MMBTU related to basis swap contracts in Energy Marketing.

(b)  Includes an aggregate 3,500,000 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 energy-related derivatives and interest rate derivatives was reflected in the condensed consolidated balance sheet as follows:

	Fair Values of Derivative Instruments
	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
Millions of dollars	Location	Value		Location	Value
As of September 30, 2013
Derivatives designated as hedging instruments
Interest rate	Prepayments and other	$	83	Other current liabilities	$	5
	Other deferred debits and other assets	41		Other deferred credits and other liabilities	19
Commodity				Other current liabilities	3
Total		$	124		$	27
Derivatives not designated as hedging instruments
Commodity	Prepayments and other	$	1
Energy Management	Prepayments and other	5		Prepayments and other	$	1
				Other current liabilities	4
	Other deferred debits and other assets	5		Other deferred credits and other liabilities	5
Total		$	11		$	10

As of December 31, 2012
Derivatives designated as hedging instruments
Interest rate	Prepayments and other	$	42	Other current liabilities	$	70
	Other deferred debits and other assets	31		Other deferred credits and other liabilities	36
Commodity	Prepayments and other	1		Other current liabilities	4
Total		$	74		$	110
Derivatives not designated as hedging instruments
Commodity	Prepayments and other	$	1
Energy management	Prepayments and other	7		Prepayments and other	$	1
	Other deferred debits and other assets	6		Other current liabilities	6
				Other deferred debits and other assets	6
Total		$	14		$	13

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

Derivatives in Cash Flow Hedging Relationships

	Gain Deferred in Regulatory Accounts					Loss Reclassified from Deferred Accounts into Income
Millions of dollars	(Effective Portion)					(Effective Portion)
September 30,	2013		2012		Location	2013			2012
Three Months Ended
Interest rate	$	19	$	23	Interest expense	$	(1	)	$	(1	)
Nine Months Ended
Interest rate	$	115	$	51	Interest expense	$	(2	)	$	(2	)

	Gain (Loss) Recognized in OCI, net of tax							Loss Reclassified from AOCI into Income, net of tax
Millions of dollars	(Effective Portion)							(Effective Portion)
September 30,	2013			2012			Location	2013			2012
Three Months Ended
Interest rate	—			$	(1	)	Interest expense	$	(2	)	$	(2	)
Commodity	$	(1	)	2			Gas purchased for resale	—			(1		)
Total	$	(1	)	$	1			$	(2	)	$	(3	)
Nine Months Ended
Interest rate	$	4		$	(5	)	Interest expense	$	(5	)	$	(5	)
Commodity	(1		)	(1		)	Gas purchased for resale	(2		)	(12		)
Total	$	3		$	(6	)		$	(7	)	$	(17	)

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 Recognized in Income
Millions of dollars	Location	2013	2012
Three Months Ended September 30,
Commodity	Gas purchased for resale	—	—
Nine Months Ended September 30,
Commodity	Gas purchased for resale	—	$	(1	)

Offseting Assets [Table Text Block]

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

						Gross Amounts Not Offset in the Statement of Financial Position
Millions of dollars	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Financial Instruments			Cash Collateral Received	Net Amount
As of September 30, 2013
Interest rate	$	124	—	$	124	$	(3	)	—	$	121
Commodity	1		—	1		—			—	1
Energy Management	10		—	10		—			—	10
Total	$	135	—	$	135	$	(3	)	—	$	132
Balance sheet location	Prepayments and other			$	89
	Other deferred debits and other assets			46
	Total			$	135

As of December 31, 2012
Interest rate	$	73	—			$	73	$	(17	)	—	$	56
Commodity	2		—			2		—			—	2
Energy Management	13		$	(1	)	12		—			—	12
Total	$	88	$	(1	)	$	87	$	(17	)	—	$	70
Balance sheet location	Prepayments and other					$	50
	Other deferred debits and other assets					37
	Total					$	87

Offsetting Liabilities [Table Text Block]

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

						Gross Amounts Not Offset in the Statement of Financial Position
Millions of dollars	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Financial Instruments			Cash Collateral Posted			Net Amount
As of September 30, 2013
Interest rate	$	24	—	$	24	$	(3	)	$	(21	)	—
Commodity	3		—	3		—			(1		)	$	2
Energy Management	10		—	10		—			(8		)	2
	$	37	—	$	37	$	(3	)	$	(30	)	$	4
Balance sheet location	Prepayments and other			$	1
	Other current liabilities			12
	Other deferred credits and other liabilities			24
	Total			$	37

As of December 31, 2012
Interest rate	$	106	—			$	106	$	(17	)	$	(67	)	$	22
Commodity	4		—			4		—			—			4
Energy Management	13		$	(1	)	12		—			(11		)	1
	$	123	$	(1	)	$	122	$	(17	)	$	(78	)	$	27
Balance sheet location	Other current liabilities					$	80
	Other deferred credits and other liabilities					42
	Total					$	122

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 reflected in the condensed consolidated balance sheet as follows:

	Fair Values of Derivative Instruments
	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
Millions of dollars	Location	Value		Location	Value
As of September 30, 2013
Derivatives designated as hedging instruments
Interest rate	Prepayments and other	$	83	Other current liabilities	$	2
	Other deferred debits and other assets	41		Other deferred credits and other liabilities	1
Total		$	124		$	3
As of December 31, 2012
Derivatives designated as hedging instruments
Interest rate	Prepayments and other	$	42	Other current liabilities	$	66
	Other deferred debits and other assets	31		Other deferred credits and other liabilities	9
Total		$	73		$	75

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

Derivatives in Cash Flow Hedging Relationships	Gain Deferred in Regulatory Accounts					Loss Reclassified from Deferred Accounts into Income
	(Effective Portion)					(Effective Portion)
Millions of dollars	2013		2012		Location	2013			2012
Three Months Ended September 30,
Interest rate	$	19	$	23	Interest expense	$	(1	)	$	(1	)
Nine Months Ended September 30,
Interest rate	$	115	$	51	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 Recognized in Income
Millions of dollars	Location	2013	2012
Three Months Ended September 30,
Commodity	Gas purchased for resale	—	—
Nine Months Ended September 30,
Commodity	Gas purchased for resale	—	$	(1	)

Offseting Assets [Table Text Block]

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

						Gross Amounts Not Offset in the Statement of Financial Position
Millions of dollars	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Financial Instruments			Cash Collateral Received	Net Amount
As of September 30, 2013
Interest rate	$	124	—	$	124	$	(3	)	—	$	121
Balance Sheet Location	Prepayments and other			$	83
	Other deferred debits and other assets			41
	Total			$	124

As of December 31, 2012
Interest rate	$	73	—	$	73	$	(17	)	—	$	56
Balance Sheet Location	Prepayments and other			$	42
	Other deferred debits and other assets			31
	Total			$	73

Offsetting Liabilities [Table Text Block]

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

						Gross Amounts Not Offset in the Statement of Financial Position
Millions of dollars	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Financial Instruments			Cash Collateral Posted		Net Amount
As of September 30, 2013
Interest rate	$	3	—	$	3	$	(3	)	$	—	$	—
Balance Sheet Location	Other current liabilities			$	2
	Other deferred credits and other liabilities			1
	Total			$	3

As of December 31, 2012
Interest rate	$	75	—	$	75	$	(17	)	$	(35	)	$	23
Balance Sheet Location	Other current liabilities			$	66
	Other deferred credits and other liabilities			9
	Total			$	75

XML

AFFILIATED TRANSACTIONS - SCEG AFFILIATED TRANSACTIONS -SCEG (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended		12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$ 40.3		$ 45.8
Canadys Refined Coal LLC [Member]
Related Party Transaction [Line Items]
Equity Method Investment, Ownership Percentage	40.00%
Cope Refined Coal LLC [Member]
Related Party Transaction [Line Items]
Related Party Transaction Purchases from Related Party	73.7	87.3
Due from Related Parties, Current	73.4	86.9
Increase (Decrease) Due from Affiliates	19.7		1.8
Equity Method Investment, Dividends or Distributions	19.8		1.8
SCEG
Related Party Transaction [Line Items]
Due to Affiliate, Current	122.0		124.0
SCEG | Canadys Refined Coal LLC [Member]
Related Party Transaction [Line Items]
Equity Method Investment, Ownership Percentage			10.00%
CGT [Member]
Related Party Transaction [Line Items]
Related Party Transaction Purchases from Related Party	25.3	27.1
Due to Affiliate, Current	3.0		3.4
Retail Gas Marketing and Energy Marketing
Related Party Transaction [Line Items]
Due to Affiliate, Current	13.2		13.1
Cost of Natural Gas Purchases	$ 132.7	$ 84.0

XML

COMMON EQUITY (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended			9 Months Ended
	Sep. 30, 2013	Mar. 31, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012	Dec. 31, 2011
Schedule of Capitalization, Equity [Line Items]
Defined Benefit Plan, Other Information					not significant
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	$ (2)		$ (3)	$ (7)	$ (17)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	(1)		0	(1)	(1)
OtherComprehensiveIncomeLossTotalReclassificationAdjustmentIncludedInNetIncomeNetOFTax	(3)		(3)	(8)	(18)
Common Stock, Shares Authorized	200,000,000			200,000,000		200,000,000
COMMON EQUITY [Abstract]
Common Shareholders' Equity	4,598			4,598		4,154
Forward Contract Indexed to Issuer's Equity, Indexed Shares		6,600,000
Dividends declared				(212)	(194)
Total Comprehensive Income (Loss)	137		126	383	327
Common Stock, Shares, Outstanding	140,200,000			140,200,000		132,000,000
Proceeds from exercise of equity forward sales agreements		196.2
Common stock issued				273	73
Common equity	4,598		4,095	4,598	4,095	4,154	3,889
SCEG
Schedule of Capitalization, Equity [Line Items]
Common Stock, Shares Authorized	50,000,000			50,000,000		50,000,000
COMMON EQUITY [Abstract]
Stockholders' Equity Attributable to Noncontrolling Interest	117			117		114
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	4,453		3,976	4,453	3,976	4,043	3,773
Proceeds from Contributions from Parent				285	84
Dividends				(195)	(162)
Total Comprehensive Income (Loss)				320	281
Common Stock, Shares, Outstanding	40,300,000			40,300,000		40,300,000
Preferred Stock, Shares Authorized	20,000,000			20,000,000		20,000,000
Preferred Stock, Shares Outstanding	1,000			1,000		1,000
Common equity	4,336			4,336		3,929
SCEG excluding VIEs [Domain]
COMMON EQUITY [Abstract]
Proceeds from Contributions from Parent				285	84
Dividends				(190)	(157)
Common Shareholders' Equity	4,336		3,864	4,336	3,864		3,665
Total Comprehensive Income (Loss)				312	272
SCEG excluding VIEs [Member]
COMMON EQUITY [Abstract]
Common Shareholders' Equity						3,929
Genco
COMMON EQUITY [Abstract]
Stockholders' Equity Attributable to Noncontrolling Interest	117		112	117	112	114	108
Proceeds from Contributions from Parent				0	0
Dividends				(5)	(5)
Total Comprehensive Income (Loss)				8	9
Interest Rate Contract
Schedule of Capitalization, Equity [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	(2)		(2)	(5)	(5)
Commodity Contract
Schedule of Capitalization, Equity [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	$ 0		$ (1)	$ (2)	$ (12)

XML

DERIVATIVE FINANCIAL INSTRUMENTS (Details 3) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Gain (Loss) on Derivatives
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant	insignificant	insignificant	insignificant
Effect of Cash Flow Hedges on Statement of Income
Other Comprehensive Income (Loss), Unrealized Gain (Loss) On Derivatives Arising During Period, Net of Tax	$ (1,000,000)	$ 1,000,000	$ 3,000,000	$ (6,000,000)
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	(2,000,000)	(3,000,000)	(7,000,000)	(17,000,000)
Derivative, Credit Risk Related Contingent Features [Abstract]
Collateral Already Posted, Aggregate Fair Value	35,400,000		35,400,000		78,300,000
Additional collateral required to be posted to counterparties if all underlying contingent features were fully triggered					26,200,000
Aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position	35,300,000		35,300,000		104,500,000
Cashcollateralrequestedfromcounterparty	78,600,000		78,600,000		32,100,000
Derivative, net asset position	78,600,000		78,600,000		32,100,000
LetterofCreditAvailableCommodityDerivatives,assetposition	9,000,000		9,000,000		10,000,000
Commodity Derivative, net asset position	10,000,000		10,000,000		13,000,000
Interest Rate Contract
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred			6,200,000
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	19,000,000	23,000,000	115,000,000	51,000,000
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income Effective Portion, Net	(1,000,000)	(1,000,000)	(2,000,000)	(2,000,000)
Effect of Cash Flow Hedges on Statement of Income
Other Comprehensive Income (Loss), Unrealized Gain (Loss) On Derivatives Arising During Period, Net of Tax	0	(1,000,000)	4,000,000	(5,000,000)
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	(2,000,000)	(2,000,000)	(5,000,000)	(5,000,000)
Commodity Contract
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred			2,000,000
Effect of Cash Flow Hedges on Statement of Income
Other Comprehensive Income (Loss), Unrealized Gain (Loss) On Derivatives Arising During Period, Net of Tax	1,000,000	(2,000,000)	1,000,000	1,000,000
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	0	(1,000,000)	(2,000,000)	(12,000,000)
Derivatives not designated as hedging instruments - gain (loss) recognized in income, classified in gas purchased for resale	0	0	0	(1,000,000)
SCEG
Gain (Loss) on Derivatives
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial	insignificant	insignificant	insignificant	insignificant
Effect of Cash Flow Hedges on Statement of Income
Derivatives not designated as hedging instruments - gain (loss) recognized in income, classified in gas purchased for resale	0	0	0	(1,000,000)
Derivative, Credit Risk Related Contingent Features [Abstract]
Collateral Already Posted, Aggregate Fair Value	3,300,000		3,300,000		35,200,000
Additional collateral required to be posted to counterparties if all underlying contingent features were fully triggered					22,700,000
Aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position	2,600,000		2,600,000		57,900,000
Cashcollateralrequestedfromcounterparty	78,600,000		78,600,000		32,100,000
Derivative, net asset position	78,600,000		78,600,000		32,100,000
SCEG | Interest Rate Contract
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	19,000,000	23,000,000	115,000,000	51,000,000
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income Effective Portion, Net	$ (1,000,000)	$ (1,000,000)	$ (2,000,000)	$ (2,000,000)

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RATE AND OTHER REGULATORY MATTERS (Details) (USD $)	9 Months Ended	12 Months Ended	3 Months Ended	9 Months Ended		12 Months Ended						3 Months Ended						9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Dec. 31, 2012 SCEG	Sep. 30, 2013 SCEG	Sep. 30, 2012 SCEG	May 01, 2015 SCEG	Dec. 31, 2012 SCEG	May 15, 2014 SCEG	Oct. 01, 2013 SCEG	Mar. 31, 2013 SCEG	Jun. 30, 2012 SCEG	Mar. 31, 2012 PSNC Energy	Sep. 30, 2013 PSNC Energy	Sep. 30, 2013 Deferred Pollution Control Costs	Dec. 31, 2012 Deferred Pollution Control Costs	Sep. 30, 2013 Deferred Pollution Control Costs SCEG	Dec. 31, 2012 Deferred Pollution Control Costs SCEG	Sep. 30, 2013 Franchise agreement Costs	Dec. 31, 2012 Franchise agreement Costs	Sep. 30, 2013 Franchise agreement Costs SCEG	Dec. 31, 2012 Franchise agreement Costs SCEG
Rate Matters [Line Items]
Regulatory Assets, Noncurrent	$ 1,333,000,000	$ 1,464,000,000	$ 1,377,000,000	$ 1,259,000,000			$ 1,377,000,000						$ 2,900,000	$ 37,000,000	$ 38,000,000	$ 37,000,000	$ 38,000,000	$ 32,000,000	$ 36,000,000	$ 32,000,000	$ 36,000,000
Amounts Recovered Through Electric Rates to offset Turbine Expenses				17,200,000
Share in Approved Capital Costs							8,000,000
Undercollected balance fuel											80,600,000
Number of coal fired units to be retired			6	2			6			6
Public Utilities, Percent Increase (Decrease) in Retail Electric Rates			4.23%		2.90%		2.30%
Allowable return on common equity (as a percent)			10.25%	11.00%
historical average temperature							15
Demand Side Management Program Costs, Noncurrent			19,600,000	16,900,000			19,600,000	10,300,000
Regulatory Asset Recovery Assessments						12
Public Utilities Property Plant and Equipment Identifiable Capital Costs							278,000,000
Capital Cost Related to New Federal Healthcare Etc							1,000,000
Public Utilities Additional Labor Expenses for Oversight of New Units							132,000,000
Increase (decrease) in retail electric rate requested under the BLRA				67.2			0
Public Utilities, Percent Increase (Decrease) in Retail Natural Gas Rates		2.10%
Public Utilities changes in Retail Natural Gas Rates Requested and Approved under RSA		0
Basis for rate calculation				12-month rolling average								12
Regulatory Noncurrent Asset Amortization Period	30			30														20
Public Utilities Base Fuel under Collected Balance Recovery Period	12			12	12
MPG enviromental remediatio	26
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority			$ 63,000,000				$ 63,000,000		$ 14,000,000

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EMPLOYEE BENEFIT PLANS (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Pension and Other Postretirement Benefit Plans
Pension Contributions			No
Components of Net Periodic Benefit Cost
Defined Benefit Plan, Curtailments	$ 9.9		$ 9.9
Pension curtailment deferred in reg asset	6.3
Increase (Decrease) in Pension Plan Obligations	128
Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	5.1	5.0	16.9	14.7
Interest cost	9.5	10.9	28.4	32.2
Expected return on assets	(15.1)	(15.0)	(45.8)	(44.6)
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	1.5	1.8	4.9	5.3
Defined Benefit Plan, Amortization of Transition Obligations (Assets)	0	0	0	0
Defined Benefit Plan, Actuarial Net (Gains) Losses	3.5	4.5	14.4	13.8
Defined Benefit Plan, Net Periodic Benefit Cost	14.4	7.2	28.7	21.4
Other Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	1.2	1.1	4.4	3.6
Interest cost	2.8	2.9	8.3	8.9
Expected return on assets	0	0	0	0
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	0.1	0.2	0.5	0.7
Defined Benefit Plan, Amortization of Transition Obligations (Assets)	0	0.2	0.3	0.5
Defined Benefit Plan, Actuarial Net (Gains) Losses	0.8	0	2.5	0.4
Defined Benefit Plan, Net Periodic Benefit Cost	4.9	4.4	16.0	14.1
SCEG
Components of Net Periodic Benefit Cost
Defined Benefit Plan, Curtailments	8.4		8.4
Pension Costs Related to Retail Electric Operations and Natural Gas Operations Deferred as Regulatory Assets	1.2	4.0	2.4	11.4
Pension curtailment deferred in reg asset	5.4
Increase (Decrease) in Pension Plan Obligations	108
SCEG | Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	4.1	4.1	13.7	11.8
Interest cost	8.0	9.1	24.0	27.3
Expected return on assets	(12.7)	(12.6)	(38.7)	(37.8)
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	1.3	1.6	4.1	4.5
Defined Benefit Plan, Actuarial Net (Gains) Losses	3.0	3.7	12.2	11.7
Defined Benefit Plan, Net Periodic Benefit Cost	12.1	5.9	23.7	17.5
SCEG | Other Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	1.0	0.8	3.5	2.8
Interest cost	2.1	2.3	6.5	7.0
Expected return on assets	0	0	0	0
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	0.1	0.1	0.4	0.5
Defined Benefit Plan, Actuarial Net (Gains) Losses	0.7	0.1	2.0	0.3
Defined Benefit Plan, Net Periodic Benefit Cost	$ 3.9	$ 3.3	$ 12.4	$ 10.6

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LONG-TERM AND SHORT-TERM DEBT LONG-TERM AND SHORT-TERM DEBT (Tables)

9 Months Ended

Sep. 30, 2013

Short-term Debt [Line Items]

Long-term Debt [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, 2013			December 31, 2012			September 30, 2013			December 31, 2012			September 30, 2013		December 31, 2012
Lines of credit:
Total committed long-term	$	300		$	300		$	1,400		$	1,400		$	100	$	100
LOC advances	—			—			—			—			—		—
Weighted average interest rate	—			—			—			—			—		—
Outstanding commercial paper (270 or fewer days)	$	68		$	142		$	310		$	449		—		$	32
Weighted average interest rate	0.43		%	0.58		%	0.30		%	0.42		%	—		0.44		%
Letters of credit supported by LOC	$	3		$	3		$	0.3		$	0.3		—		—
Available	$	229		$	155		$	1,090		$	951		$	100	$	68

SCEG

Short-term Debt [Line Items]

Long-term Debt [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, 2013			December 31, 2012
Lines of credit:
Total committed long-term	$	1,400		$	1,400
LOC advances	—			—
Weighted average interest rate	—			—
Outstanding commercial paper (270 or fewer days)	$	310		$	449
Weighted average interest rate	0.30		%	0.42		%
Letters of credit supported by LOC	$	0.3		$	0.3
Available	$	1,090		$	951

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Net Income (Loss) Attributable to Parent [Abstract]
Income Available to Common Shareholders	$ 131	$ 122	$ 368	$ 315
Other Comprehensive Income (Loss)
Unrealized gains (losses) on cash flow hedging activities arising during period	(1)	1	3	(6)
Losses on cash flow hedging activities reclassified to net income	2	3	7	17
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax	4	0	4	0
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	1	0	1	1
Other Comprehensive Income	(6)	(4)	(15)	(12)
Total Comprehensive Income (Loss)	137	126	383	327
SCEG
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	139	132	319	281
Other Comprehensive Income (Loss)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax	1	0	1	0
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	140	132	320	281
Total Comprehensive Income (Loss)			320	281
Genco
Other Comprehensive Income (Loss)
Less comprehensive income attributable to noncontrolling interest	(3)	(3)	(8)	(9)
Total Comprehensive Income (Loss)			8	9
SCE&G (including Fuel Company)
Other Comprehensive Income (Loss)
Total Comprehensive Income (Loss)	$ 137	$ 129	$ 312	$ 272

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Cash Flows From Operating Activities:
Income Available to Common Shareholders of SCANA	$ 368	$ 315
Adjustments to reconcile net income to net cash provided from operating activities:
Deferred income taxes, net	62	74
Depreciation and amortization	294	277
Amortization of nuclear fuel	42	38
Allowance for equity funds used during construction	(19)	(13)
Cash provided (used) by changes in certain assets and liabilities:
Receivables	70	46
Inventories	(8)	(34)
Prepayments and other	8	58
Regulatory liabilities	78	47
Accounts payable	(32)	(7)
Taxes accrued	(27)	(21)
Interest accrued	(7)	4
Regulatory assets	142	(2)
Pension and Postretirement Obligations	(133)	3
Changes in other assets	(46)	4
Changes in other liabilities	(13)	(21)
Net Cash Provided From Operating Activities	779	768
Cash Flows From Investing Activities:
Property additions and construction expenditures	(868)	(868)
Proceeds from investments (including derivative collateral posted)	199	364
Purchase of investments (including derivative collateral posted)	(161)	(326)
Proceeds from Hedge, Investing Activities	43	14
Payments for interest rate contract settlements	(49)	(51)
Net Cash Used in Investing Activities	(836)	(867)
Cash Flows From Financing Activities:
Proceeds from Issuance of Common Stock	272	73
Proceeds from issuance of long-term debt	451	763
Repayments of Long-term Debt	(256)	(274)
Dividends	(207)	(192)
Short-term borrowings, net	(245)	(259)
Net Cash Provided From Financing Activities	15	111
Net (Decrease) Increase in Cash and Cash Equivalents	(42)	12
Cash and Cash Equivalents, January 1	72	29
Cash and Cash Equivalents, September 30	30	41
Supplemental Cash Flow Information:
Cash paid for-Interest (net of capitalized interest )	222	212
Cash paid for-Income taxes	70	67
Noncash Investing and Financing Activities:
Accrued construction expenditures	97	79
Capital Lease Obligations Incurred	5	4
Noncash or Part Noncash Acquisition, Value of Assets Acquired	98	0
SCEG
Cash Flows From Operating Activities:
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	319	281
Adjustments to reconcile net income to net cash provided from operating activities:
Deferred income taxes, net	49	74
Depreciation and amortization	237	221
Amortization of nuclear fuel	42	38
Allowance for equity funds used during construction	(18)	(12)
Cash provided (used) by changes in certain assets and liabilities:
Receivables	(58)	(22)
Inventories	5	(49)
Prepayments and other	(51)	(57)
Regulatory liabilities	80	49
Accounts payable	(7)	13
Taxes accrued	7	(8)
Interest accrued	(10)	(1)
Regulatory assets	129	(1)
Pension and Postretirement Obligations	(117)	0
Changes in other assets	(30)	47
Changes in other liabilities	(3)	(20)
Net Cash Provided From Operating Activities	574	553
Cash Flows From Investing Activities:
Property additions and construction expenditures	(794)	(793)
Proceeds from investments (including derivative collateral posted)	139	196
Purchase of investments (including derivative collateral posted)	(112)	(199)
Proceeds from Hedge, Investing Activities	43	14
Payments for interest rate contract settlements	(49)	0
Net Cash Used in Investing Activities	(773)	(782)
Cash Flows From Financing Activities:
Proceeds from issuance of long-term debt	451	517
Repayments of Long-term Debt	(248)	(13)
Dividends	(174)	(146)
Contributions from parent	285	84
Short-term borrowings, net	(139)	(185)
Short-term borrowings- affiliate,net	(10)	(9)
Net Cash Provided From Financing Activities	165	248
Net (Decrease) Increase in Cash and Cash Equivalents	(34)	19
Cash and Cash Equivalents, January 1	51	16
Cash and Cash Equivalents, September 30	17	35
Supplemental Cash Flow Information:
Cash paid for-Interest (net of capitalized interest )	160	147
Cash paid for-Income taxes	67	81
Noncash Investing and Financing Activities:
Accrued construction expenditures	89	66
Capital Lease Obligations Incurred	3	4
Noncash or Part Noncash Acquisition, Value of Assets Acquired	$ 98	$ 0

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RATE AND OTHER REGULATORY MATTERS

9 Months Ended

Sep. 30, 2013

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. In April 2012, the SCPSC approved SCE&G's request to decrease the total fuel cost component of its retail electric rates, and approved a settlement agreement among SCE&G, the ORS and SCEUC in which SCE&G agreed to recover an amount equal to its under-collected balance of base fuel and variable environmental costs as of April 30, 2012, or $80.6 million, over a 12-month period beginning with the first billing cycle of May 2012.

This April 2012 order was superseded, in part, by a December 2012 rate order in which the SCPSC authorized SCE&G to reduce the base fuel cost component of its retail electric rates and, in doing so, stated that SCE&G may not adjust its base fuel cost component prior to the last billing cycle of April 2014, except where necessary due to extraordinary unforeseen economic or financial conditions.  In February 2013, in connection with its annual review of base rates for fuel costs, SCE&G requested authorization to reduce its environmental fuel cost component effective with the first billing cycle of May 2013.  Consistent with the December 2012 rate order, SCE&G did not request any adjustment to its base fuel cost component.  On March 14, 2013, SCE&G, ORS and the SCEUC entered into a settlement agreement accepting the proposed lower environmental fuel cost component effective with the first billing cycle of May 2013, and providing for the accrual of certain debt-related carrying costs on a portion of the undercollected balance of fuel costs. The SCPSC issued an order dated April 30, 2013, adopting and approving the settlement agreement and approving SCE&G's total fuel cost component.

Electric - Base Rates

On December 19, 2012, the SCPSC approved a 4.23% overall increase in SCE&G's retail electric base rates, effective January 1, 2013, and authorized an allowed return on common equity of 10.25%. The SCPSC also approved a mid-period reduction to the cost of fuel component in rates (as discussed above), a reduction in the DSM Programs component rider to retail rates, and the recovery of and a return on the net carrying value of certain retired generating plant assets described below. By order dated February 7, 2013, the SCPSC denied the SCEUC's petition for rehearing of this order and the order was not appealed.

The eWNA is designed to mitigate the effects of abnormal weather on residential and commercial customers' bills and is based on a 15 year historical average of temperatures. In connection with the December 2012 rate order, SCE&G agreed to perform a study of alternative structures for the eWNA. The study was completed and filed with the SCPSC on June 28, 2013. In the study, SCE&G proposed that no adjustment or modification to the eWNA be made at this time. On November 1, 2013, the ORS filed a report with the SCPSC recommending that the eWNA be terminated with the last billing cycle for December 2013. SCE&G will be working with the ORS to address its recommendation. SCE&G cannot predict what action the SCPSC may take, if any.

In February 2013, SCE&G filed an IRP with the SCPSC. The IRP evaluates future electric generation needs based on a variety of factors, including customer energy demands, EPA regulations, reserve margins and fuel costs. The IRP identified a total of six coal-fired units that SCE&G retired or intends to retire by 2018, subject to future developments in environmental regulations, among other matters. One of these units was retired in 2012, and its net carrying value is recorded in regulatory assets as unrecovered plant and is being amortized over its previously estimated remaining useful life. The net carrying value of the remaining units is included in Plant to be Retired, Net in the consolidated financial statements. In connection with their retirement, SCE&G expects to be allowed a recovery of and a return on the net carrying value of these remaining units through rates. In the meantime, these units remain in rate base, and SCE&G continues to depreciate them using composite straight-line rates approved by the SCPSC. As discussed in Note 1, SCE&G approved a plan to accelerate the retirement of two of the units by the end of 2013 and has received SCPSC approval to record the net carrying value of these units in regulatory assets as unrecovered plant once they are retired.

SCE&G's DSM Programs for electric customers provide for an annual rider, approved by the SCPSC, to allow recovery of the costs and net lost revenue associated with the DSM Programs, along with an incentive for investing in such programs. SCE&G submits annual filings regarding the DSM Programs, net lost revenues, program costs, incentives and net program benefits. The SCPSC has approved the following rate changes pursuant to annual DSM Programs filings, which changes became effective as indicated:

Year	Effective	Amount
2013	First billing cycle of May	$16.9 million
2012	First billing cycle of May	$19.6 million

In addition, the SCPSC approved the deferral of an additional $10.3 million of net lost revenues and provided for their recovery over a 12-month period beginning with the first billing cycle in May 2014.

SCE&G's initial authorization to operate its DSM Programs expires November 30, 2013. On May 31, 2013, SCE&G filed a request with the SCPSC for approval to extend the operation of its portfolio of DSM Programs.  SCE&G also requested approval to continue the use of the annual rate rider which (i) maintains the same terms and conditions currently in effect for the recovery of costs associated with the proposed DSM Programs, the net lost revenue associated with its DSM Programs, and an appropriate incentive for investing in such programs, and (ii) modifies the opt-out requirements for industrial customers.  SCE&G requested that the proposed DSM Programs and rate rider authorization be effective December 1, 2013.  

On October 21, 2013, SCE&G entered into a Settlement Agreement with ORS, Wal-Mart Stores East, LP, Sam’s East, Inc. and the SCEUC. Under the Settlement Agreement, the settling parties agreed that SCE&G’s revised portfolio of DSM Programs should be approved as filed by SCE&G.  As for the annual rate rider, the settling parties agreed that SCE&G should be allowed to (i) continue to defer and amortize all prudently incurred costs for the DSM Programs over five years with carrying costs, (ii) calculate the net lost revenues component of the DSM Programs rider utilizing a rolling three year period of program history, and (iii) continue to recover a shared savings incentive, among other things.  The settling parties also agreed that SCE&G’s DSM Programs should continue for six years. Two other parties in the case did not execute the Settlement Agreement.  A public hearing on this matter was held on October 24, 2013, and the SCPSC's ruling is pending.

Electric – BLRA

In November 2012, the SCPSC approved an updated construction schedule and additional updated capital costs of $278 million (SCE&G's portion in 2007 dollars). The November 2012 order approved additional identifiable capital costs of approximately $1 million (SCE&G's portion in 2007 dollars) related to new federal healthcare laws, information security measures, and certain minor design modifications; approximately $8 million (SCE&G's portion in 2007 dollars) related to transmission infrastructure; and approximately $132 million (SCE&G's portion in 2007 dollars) related to additional labor for the oversight of the New Units during construction and for preparing to operate the New Units, and facilities and information technology systems required to support the New Units and their personnel. In addition, the order approved revised substantial completion dates for the New Units based on the March 30, 2012 issuance of the COL and the amounts agreed upon by SCE&G and the Consortium in July 2012 to resolve claims for costs related to COL delays, design modifications of the shield building and certain pre-fabricated structural modules for the New Units and unanticipated rock conditions at the site. Thereafter, two parties filed separate petitions requesting that the SCPSC reconsider its November 2012 order. On December 12, 2012, the SCPSC denied both petitions. In March 2013, both parties appealed the SCPSC's order to the South Carolina Supreme Court. SCE&G is unable to predict the outcome of these appeals. For further discussion of new nuclear construction matters, see Note 9.

Under the BLRA, SCE&G is allowed to 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. Requested rate adjustments are 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 the following rate changes under the BLRA effective for bills rendered on and after October 30 in the years indicated:

Year	Action			Amount
2013	2.9	%	Increase	$67.2 million
2012	2.3	%	Increase	$52.1 million

Gas

SCE&G

The RSA is designed to reduce the volatility of costs charged to customers by allowing for 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 years indicated:

Year	Action			Amount
2013	No change			-
2012	2.1	%	Increase	$7.5 million

On June 5, 2013, SCE&G submitted its annual RSA filing with the SCPSC for the 12-month period ending March 31, 2013. SCE&G earned a return on its gas distribution operations, after proforma adjustments, that is within the range of its allowable rate of return on common equity. The SCPSC approved SCE&G’s annual RSA filing on October 9, 2013, with no change in rates.

SCE&G's natural gas tariffs include a PGA clause that provides for the recovery of actual gas costs incurred. 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. The 2012 annual PGA hearing to review SCE&G's gas purchasing policies and procedures was held in November 2012 before the SCPSC. The SCPSC issued an order in December 2012 finding that SCE&G's gas purchasing policies and practices during the review period of August 1, 2011 through July 31, 2012, were reasonable and prudent. SCE&G’s 2013 annual PGA hearing was held on November 7, 2013, and the SCPSC's ruling is pending.

PSNC Energy

PSNC Energy is subject to a Rider D rate mechanism which allows it to recover from customers all prudently incurred gas costs and certain uncollectible expenses related to gas cost.  The Rider D rate mechanism also allows PSNC Energy to recover, in any manner authorized by the NCUC, losses on negotiated gas and transportation sales.

PSNC Energy’s rates are established 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 with the NCUC 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 September 2013, in connection with PSNC Energy's 2013 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, 2013.

Regulatory Assets and Regulatory Liabilities

The Company’s cost-based, rate-regulated utilities recognize in their financial statements certain revenues and expenses in different time periods than do enterprises that are not rate-regulated.  As a result, the Company has recorded regulatory assets and regulatory liabilities which are summarized in the following tables.  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, 2013		December 31, 2012
Regulatory Assets:
Accumulated deferred income taxes	$	254	$	254
Under-collections - electric fuel adjustment clause	52		66
Environmental remediation costs	42		44
AROs and related funding	359		319
Franchise agreements	32		36
Deferred employee benefit plan costs	319		460
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	126		151
Deferred pollution control costs	37		38
Unrecovered plant	19		20
Other	93		70
Total Regulatory Assets	$	1,333	$	1,464

Regulatory Liabilities:
Accumulated deferred income taxes	$	19	$	21
Asset removal costs	718		692
Storm damage reserve	27		27
Monetization of bankruptcy claim	30		32
Deferred gains on interest rate derivatives	203		110
Planned major maintenance	10		—
Total Regulatory Liabilities	$	1,007	$	882

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 70 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 during annual hearings which are not expected to be recovered in retail electric rates within 12 months. 

Environmental remediation costs represent costs associated with the assessment and clean-up of MGP sites currently or formerly owned by the Company.  These regulatory assets are expected to be recovered over periods of up to approximately 26 years.

ARO and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station and conditional AROs.  These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 90 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 began amortizing these amounts through cost of service rates in February 2003 over approximately 20 years.

Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under generally accepted accounting principles. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. In connection with the December 2012 rate order, approximately $63 million of deferred pension costs for electric operations are to be recovered through utility rates over approximately 30 years. In connection with the October 2013 RSA order, approximately $14 million of deferred pension costs for gas operations are to be recovered through utility rates 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, as approved pursuant to specific SCPSC orders.  SCE&G collects $18.4 million annually for fossil fueled turbine/generation equipment maintenance.  Through December 31, 2012, nuclear refueling charges were accrued during each 18-month refueling outage cycle as a component of cost of service. In connection with the December 2012 rate order, effective January 1, 2013, SCE&G began to collect and accrue $17.2 million annually for nuclear-related refueling charges.

Deferred losses or gains on interest rate derivatives generally represent the unrealized losses or gains from fair value adjustments and payments made or received upon termination of certain interest rate derivatives.  These amounts are expected to be amortized to interest expense over the lives of the underlying debt, up to approximately 30 years, unless, in the case of gains, such amounts are applied otherwise at the direction of regulators.

Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the scrubbers installed at Wateree and Williams Stations pursuant to specific regulatory orders.  Such costs are being recovered through utility rates over periods up to approximately 30 years. 

Unrecovered plant represents the net book value of a coal-fired generating unit retired from service prior to being fully depreciated. Pursuant to the December 2012 rate order, SCE&G is amortizing these amounts over the unit's previously estimated remaining useful life of approximately 14 years. Unamortized amounts are included in rate base.

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.

The monetization of bankruptcy claim represents proceeds from the sale of a bankruptcy claim which are being amortized into operating revenue through February 2024.

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 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 by SCE&G. In April 2012, the SCPSC approved SCE&G's request to decrease the total fuel cost component of its retail electric rates, and approved a settlement agreement among SCE&G, the ORS and SCEUC in which SCE&G agreed to recover an amount equal to its under-collected balance of base fuel and variable environmental costs as of April 30, 2012, or $80.6 million, over a 12-month period beginning with the first billing cycle of May 2012.

This April 2012 order was superseded, in part, by a December 2012 rate order in which the SCPSC authorized SCE&G to reduce the base fuel cost component of its retail electric rates and, in doing so, stated that SCE&G may not adjust its base fuel cost component prior to the last billing cycle of April 2014, except where necessary due to extraordinary unforeseen economic or financial conditions.  In February 2013, in connection with its annual review of base rates for fuel costs, SCE&G requested authorization to reduce its environmental fuel cost component effective with the first billing cycle of May 2013.  Consistent with the December 2012 rate order,SCE&G did not request any adjustment to its base fuel cost component.  On March 14, 2013, SCE&G, ORS and the SCEUC entered into a settlement agreement accepting the proposed lower environmental fuel cost component effective with the first billing cycle of May 2013, and providing for the accrual of certain debt-related carrying costs on a portion of the undercollected balance of fuel costs. The SCPSC issued an order dated April 30, 2013, adopting and approving the settlement agreement and approving SCE&G's total fuel cost component.

Electric - Base Rates

On December 19, 2012, the SCPSC approved a 4.23% overall increase in SCE&G's retail electric base rates, effective January 1, 2013, and authorized an allowed return on common equity of 10.25%. The SCPSC also approved a mid-period reduction to the cost of fuel component in rates (as discussed above), a reduction in the DSM Programs component rider to retail rates, and the recovery of and a return on the net carrying value of certain retired generating plant assets described below. By order dated February 7, 2013, the SCPSC denied the SCEUC's petition for rehearing of this order and the order was not appealed.

The eWNA is designed to mitigate the effects of abnormal weather on residential and commercial customers' bills and is based on a 15 year historical average of temperatures. In connection with the December 2012 rate order, SCE&G agreed to perform a study of alternative structures for the eWNA. The study was completed and filed with the SCPSC on June 28, 2013. In the study, SCE&G proposed that no adjustment or modification to the eWNA be made at this time.  On November 1, 2013, the ORS filed a report with the SCPSC recommending that the eWNA be terminated with the last billing cycle for December 2013. SCE&G will be working with the ORS to address its recommendation. SCE&G cannot predict what action the SCPSC may take, if any.

In February 2013, SCE&G filed an IRP with the SCPSC. The IRP evaluates future electric generation needs based on a variety of factors, including customer energy demands, EPA regulations, reserve margins and fuel costs. The IRP identified a total of six coal-fired units that SCE&G retired or intends to retire by 2018, subject to future developments in environmental regulations, among other matters. One of these units was retired in 2012, and its net carrying value is recorded in regulatory assets as unrecovered plant and is being amortized over its previously estimated remaining useful life. The net carrying value of the remaining units is included in Plant to be Retired, Net in the consolidated financial statements. In connection with their retirement, SCE&G expects to be allowed a recovery of and a return on the net carrying value of these remaining units through rates. In the meantime, these units remain in rate base, and SCE&G continues to depreciate them using composite straight-line rates approved by the SCPSC. As discussed in Note 1, SCE&G approved a plan to accelerate the retirement of two of the units by the end of 2013 and has received SCPSC approval to record the net carrying value of these units in regulatory assets as unrecovered plant once they are retired.

SCE&G's DSM Programs for electric customers provide for an annual rider, approved by the SCPSC, to allow recovery of the costs and net lost revenue associated with the DSM Programs, along with an incentive for investing in such programs. SCE&G submits annual filings regarding the DSM Programs, net lost revenues, program costs, incentives and net program benefits. The SCPSC has approved the following rate changes pursuant to annual DSM Programs filings, which changes became effective as indicated:

Year	Effective	Amount
2013	First billing cycle of May	$16.9 million
2012	First billing cycle of May	$19.6 million

In addition, the SCPSC approved the deferral of an additional $10.3 million of net lost revenues and provided for their recovery over a 12-month period beginning with the first billing cycle in May 2014.

SCE&G's initial authorization to operate its DSM Programs expires November 30, 2013. On May 31, 2013, SCE&G filed a request with the SCPSC for approval to extend the operation of its portfolio of DSM Programs.  SCE&G also requested approval to continue the use of the annual rate rider which (i) maintains the same terms and conditions currently in effect for the recovery of costs associated with the proposed DSM Programs, the net lost revenue associated with its DSM Programs, and an appropriate incentive for investing in such programs, and (ii) modifies the opt-out requirements for industrial customers.  SCE&G requested that the proposed DSM Programs and rate rider authorization be effective December 1, 2013.

 On October 21, 2013, SCE&G entered into a Settlement Agreement with ORS, Wal-Mart Stores East, LP, Sam’s East, Inc. and the SCEUC.  Under the Settlement Agreement, the settling parties agreed that SCE&G’s revised portfolio of DSM Programs should be approved as filed by SCE&G.  As for the annual rate rider, the settling parties agreed that SCE&G should be allowed to (i) continue to defer and amortize all prudently incurred costs for the DSM Programs over five years with carrying costs, (ii) calculate the net lost revenues component of the DSM Programs rider utilizing a rolling three year period of program history, and (iii) continue to recover a shared savings incentive, among other things.  The settling parties also agreed that SCE&G’s DSM Programs should continue for six years. Two other parties in the case did not execute the Settlement Agreement.  A public hearing on this matter was held on October 24, 2013, and the SCPSC's ruling is pending.

Electric – BLRA

In November 2012, the SCPSC approved an updated construction schedule and additional updated capital costs of $278 million (SCE&G's portion in 2007 dollars). The November 2012 order approved additional identifiable capital costs of approximately $1 million (SCE&G's portion in 2007 dollars) related to new federal healthcare laws, information security measures, and certain minor design modifications; approximately $8 million (SCE&G's portion in 2007 dollars) related to transmission infrastructure; and approximately $132 million (SCE&G's portion in 2007 dollars) related to additional labor for the oversight of the New Units during construction and for preparing to operate the New Units, and facilities and information technology systems required to support the New Units and their personnel. In addition, the order approved revised substantial completion dates for the New Units based on the March 30, 2012 issuance of the COL and the amounts agreed upon by SCE&G and the Consortium in July 2012 to resolve claims for costs related to COL delays, design modifications of the shield building and certain pre-fabricated structural modules for the New Units and unanticipated rock conditions at the site. Thereafter, two parties filed separate petitions requesting that the SCPSC reconsider its November 2012 order. On December 12, 2012, the SCPSC denied both petitions. In March 2013, both parties appealed the SCPSC's order to the South Carolina Supreme Court. SCE&G is unable to predict the outcome of these appeals. For further discussion of new nuclear construction matters, see Note 9.

Under the BLRA, SCE&G is allowed to 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. Requested rate adjustments are 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 the following rate changes under the BLRA effective for bills rendered on and after October 30 in the years indicated:

Year	Action			Amount
2013	2.9	%	Increase	$67.2 million
2012	2.3	%	Increase	$52.1 million

Gas

The RSA is designed to reduce the volatility of costs charged to customers by allowing for 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 years indicated:

Year	Action			Amount
2013	No change			-
2012	2.1	%	Increase	$7.5 million

On June 5, 2013, SCE&G submitted its annual RSA filing with the SCPSC for the 12-month period ending March 31, 2013. SCE&G earned a return on its gas distribution operations, after proforma adjustments, that is within the range of its allowable rate of return on common equity. The SCPSC approved SCE&G’s annual RSA filing on October 9, 2013, with no change in rates.

SCE&G's natural gas tariffs include a PGA clause that provides for the recovery of actual gas costs incurred. 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. The 2012 annual PGA hearing to review SCE&G's gas purchasing policies and procedures was held in November 2012 before the SCPSC. The SCPSC issued an order in December 2012 finding that SCE&G's gas purchasing policies and practices during the review period of August 1, 2011 through July 31, 2012, were reasonable and prudent. SCE&G’s 2013 annual PGA hearing was held on November 7, 2013, and the SCPSC's ruling 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 time periods than do enterprises that are not rate-regulated.  As a result, Consolidated SCE&G has recorded regulatory assets and regulatory liabilities, which are summarized in the following tables.  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, 2013		December 31, 2012
Regulatory Assets:
Accumulated deferred income taxes	$	248	$	248
Under collections – electric fuel adjustment clause	52		66
Environmental remediation costs	37		39
AROs and related funding	342		304
Franchise agreements	32		36
Deferred employee benefit plan costs	284		405
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	126		151
Deferred pollution control costs	37		38
Unrecovered plant	19		20
Other	82		64
Total Regulatory Assets	$	1,259	$	1,377

Regulatory Liabilities:
Accumulated deferred income taxes	$	19	$	21
Asset removal costs	522		507
Storm damage reserve	27		27
Deferred gains on interest rate derivatives	203		110
Planned major maintenance	10		—
Total Regulatory Liabilities	$	781	$	665

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 70 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 during annual hearings which are not expected to be recovered in retail electric rates within 12 months. 

Environmental remediation costs represent costs associated with the assessment and clean-up of MGP sites currently or formerly owned by SCE&G.  These regulatory assets are expected to be recovered over periods of up to approximately 26 years.

ARO and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station and conditional AROs.  These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 90 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 began amortizing these amounts through cost of service rates in February 2003 over approximately 20 years.

Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under generally accepted accounting principles. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. In connection with the December 2012 rate order, approximately $63 million of deferred pension costs for electric operations are to be recovered through utility rates over approximately 30 years. In connection with the October 2013 RSA order, approximately $14 million of deferred pension costs for gas operations are to be recovered through utility rates 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 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, as approved pursuant to specific SCPSC orders.  SCE&G collects $18.4 million annually for fossil fueled turbine/generation equipment maintenance.  Through December 31, 2012, nuclear refueling charges were accrued during each 18-month refueling outage cycle as a component of cost of service. In connection with the December 2012 rate order, effective January 1, 2013, SCE&G began to collect and accrue $17.2 million annually for nuclear-related refueling charges.

Deferred losses or gains on interest rate derivatives generally represent unrealized losses or gains from fair value adjustments and payments made or received upon termination of certain interest rate derivatives.  These amounts are expected to be amortized to interest expense over the lives of the underlying debt, up to approximately 30 years, unless, in the case of gains, such amounts are applied otherwise at the direction of regulators.

Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the scrubbers installed at Wateree and Williams Stations pursuant to specific regulatory orders.  Such costs are being recovered through utility rates over periods up to approximately 30 years. 

Unrecovered plant represents the net book value of a coal-fired generating unit retired from service prior to being fully depreciated. Pursuant to the December 2012 rate order, SCE&G is amortizing these amounts over the unit's previously estimated remaining useful life of approximately 14 years. Unamortized amounts are included in rate base.

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.

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 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.

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Interest Paid, Capitalized	$ 10	$ 8
SCEG
Interest Paid, Capitalized	$ 9	$ 7

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FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	$ 135,000,000	$ 87,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	37,000,000	122,000,000
Interest Rate Contract
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	124,000,000	73,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	24,000,000	106,000,000
Commodity Contract
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	1,000,000	2,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	3,000,000	4,000,000
Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets, Fair Value Disclosure [Abstract]
Available-for-sale Securities	9,000,000	6,000,000
Quoted Prices in Active Markets for Identical Assets (Level 1) | Interest Rate Contract
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	0	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Commodity Contract
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	1,000,000	1,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other energy management contracts
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	0	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	0	1,000,000
Fair Value, Inputs, Level 2 [Member]
Assets, Fair Value Disclosure [Abstract]
Available-for-sale Securities	0	0
Fair Value, Inputs, Level 2 [Member] | Interest Rate Contract
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	124,000,000	73,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	24,000,000	106,000,000
Fair Value, Inputs, Level 2 [Member] | Commodity Contract
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	0	1,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	3,000,000	4,000,000
Fair Value, Inputs, Level 2 [Member] | Other energy management contracts
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	10,000,000	13,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	13,000,000	15,000,000
SCEG
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	124,000,000	73,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	3,000,000	75,000,000
SCEG | Interest Rate Contract
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	124,000,000	73,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	3,000,000	75,000,000
SCEG | Fair Value, Inputs, Level 2 [Member] | Interest Rate Contract
Assets, Fair Value Disclosure [Abstract]
Derivative Asset	124	73
Liabilities, Fair Value Disclosure [Abstract]
Derivative Liability	$ 3	$ 75

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EMPLOYEE BENEFIT PLANS (Tables)

9 Months Ended

Sep. 30, 2013

Pension and Other Postretirement Benefit Plans

Schedule of Net Benefit Costs [Table Text Block]

: 

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2013			2012			2013		2012
Three months ended September 30,
Service cost	$	5.1		$	5.0		$	1.2	$	1.1
Interest cost	9.5			10.9			2.8		2.9
Expected return on assets	(15.1		)	(15.0		)	—		—
Prior service cost amortization	1.5			1.8			0.1		0.2
Charge due to curtailment	9.9			—			—		—
Transition obligation amortization	—			—			—		0.2
Amortization of actuarial losses	3.5			4.5			0.8		—
Net periodic benefit cost	$	14.4		$	7.2		$	4.9	$	4.4

Nine months ended September 30,
Service cost	$	16.9		$	14.7		$	4.4	$	3.6
Interest cost	28.4			32.2			8.3		8.9
Expected return on assets	(45.8		)	(44.6		)	—		—
Prior service cost amortization	4.9			5.3			0.5		0.7
Charge due to curtailment	9.9			—			—		—
Transition obligation amortization	—			—			0.3		0.5
Amortization of actuarial losses	14.4			13.8			2.5		0.4
Net periodic benefit cost	$	28.7		$	21.4		$	16.0	$	14.1

SCEG

Pension and Other Postretirement Benefit Plans

Schedule of Net Benefit Costs [Table Text Block]

:

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2013			2012			2013		2012
Three months ended September 30,
Service cost	$	4.1		$	4.1		$	1.0	$	0.8
Interest cost	8.0			9.1			2.1		2.3
Expected return on assets	(12.7		)	(12.6		)	—		—
Prior service cost amortization	1.3			1.6			0.1		0.1
Charge due to curtailment	8.4			—			—		—
Amortization of actuarial losses	3.0			3.7			0.7		0.1
Net periodic benefit cost	$	12.1		$	5.9		$	3.9	$	3.3

Nine months ended September 30,
Service cost	$	13.7		$	11.8		$	3.5	$	2.8
Interest cost	24.0			27.3			6.5		7.0
Expected return on assets	(38.7		)	(37.8		)	—		—
Prior service cost amortization	4.1			4.5			0.4		0.5
Charge due to curtailment	8.4			—			—		—
Amortization of actuarial losses	12.2			11.7			2.0		0.3
Net periodic benefit cost	$	23.7		$	17.5		$	12.4	$	10.6

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RATE AND OTHER REGULATORY MATTERS (Details 2) (USD $) In Millions, unless otherwise specified	9 Months Ended		9 Months Ended	24 Months Ended				9 Months Ended		9 Months Ended										9 Months Ended				9 Months Ended						3 Months Ended							9 Months Ended		9 Months Ended						9 Months Ended			9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013 SCEG	Jul. 31, 2012 SCEG	May 15, 2014 SCEG	Oct. 01, 2013 SCEG	Dec. 31, 2012 SCEG	Sep. 30, 2013 Deferred Income Tax Charges [Member]	Dec. 31, 2012 Deferred Income Tax Charges [Member]	Sep. 30, 2013 Deferred Income Tax Charges [Member] SCEG	Dec. 31, 2012 Deferred Income Tax Charges [Member] SCEG	Sep. 30, 2013 Regulatory Clause Revenues, under-recovered [Member]	Dec. 31, 2012 Regulatory Clause Revenues, under-recovered [Member]	Sep. 30, 2013 Regulatory Clause Revenues, under-recovered [Member] SCEG	Dec. 31, 2012 Regulatory Clause Revenues, under-recovered [Member] SCEG	Sep. 30, 2013 Environmental Restoration Costs [Member]	Dec. 31, 2012 Environmental Restoration Costs [Member]	Sep. 30, 2013 Environmental Restoration Costs [Member] SCEG	Dec. 31, 2012 Environmental Restoration Costs [Member] SCEG	Sep. 30, 2013 Asset Retirement Obligation Costs [Member]	Dec. 31, 2012 Asset Retirement Obligation Costs [Member]	Sep. 30, 2013 Asset Retirement Obligation Costs [Member] SCEG	Dec. 31, 2012 Asset Retirement Obligation Costs [Member] SCEG	Sep. 30, 2013 Franchise agreement Costs	Dec. 31, 2012 Franchise agreement Costs	Sep. 30, 2013 Franchise agreement Costs SCEG	Dec. 31, 2012 Franchise agreement Costs SCEG	Sep. 30, 2013 Pension Costs [Member]	Dec. 31, 2012 Pension Costs [Member]	Sep. 30, 2013 Pension Costs [Member] SCEG	Mar. 31, 2013 Pension Costs [Member] SCEG	Dec. 31, 2012 Pension Costs [Member] SCEG	Sep. 30, 2013 Planned major maintenance [Member]	Dec. 31, 2012 Planned major maintenance [Member]	Sep. 30, 2013 Planned major maintenance [Member] SCEG	Dec. 31, 2012 Planned major maintenance [Member] SCEG	Sep. 30, 2013 Deferred Losses On Interest Rate Derivatives [Member]	Dec. 31, 2012 Deferred Losses On Interest Rate Derivatives [Member]	Sep. 30, 2013 Deferred Losses On Interest Rate Derivatives [Member] SCEG	Dec. 31, 2012 Deferred Losses On Interest Rate Derivatives [Member] SCEG	Sep. 30, 2013 Deferred Pollution Control Costs	Dec. 31, 2012 Deferred Pollution Control Costs	Sep. 30, 2013 Deferred Pollution Control Costs SCEG	Dec. 31, 2012 Deferred Pollution Control Costs SCEG	Sep. 30, 2013 unrecovered plant [Member]	Dec. 31, 2012 unrecovered plant [Member]	Sep. 30, 2013 unrecovered plant [Member] SCEG	Sep. 30, 2013 Other Regulatory Assets [Member]	Dec. 31, 2012 Other Regulatory Assets [Member]	Sep. 30, 2013 Other Regulatory Assets [Member] SCEG	Dec. 31, 2012 Other Regulatory Assets [Member] SCEG
Regulatory Assets
Demand Side Management Program Costs, Noncurrent			$ 16.9		$ 10.3		$ 19.6
MPG enviromental remediatio	26
Regulatory Noncurrent Asset, Amortization Period	30		30					70		70										90				20						14	12	30					30		30						14			30
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority						14	63
Regulatory Assets, Noncurrent	1,333.0	1,464.0	1,259.0				1,377.0	254.0	254.0	248.0	248.0	52.0	66.0	52.0	66.0	42.0	44.0	37.0	39.0	359.0	319.0	342.0	304.0	32.0	36.0	32.0	36.0	319.0	460.0	284.0		405.0	0	6.0	0	6.0	126.0	151.0	126.0	151.0	37.0	38.0	37.0	38.0	19.0	20.0	19.0	93.0	70.0	82.0	64.0
Amounts Recovered through Electric Rates to offset Turbine Expense				$ 18.4

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INCOME TAXES (Details)	9 Months Ended	12 Months Ended
	Sep. 30, 2013	Dec. 31, 2015	Dec. 31, 2014
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent	6.90%	5.00%	6.00%

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SEGMENT OF BUSINESS INFORMATION (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue	$ 704	$ 714	$ 1,898	$ 1,851
Intersegment Revenue	0	0
Operating Income	255	238	738	647
Regulated Operating Revenue, Gas	128	109	667	513
Regulated and Unregulated Operating Revenue	1,051	1,038	3,378	3,054
Income Available to Common Shareholders of SCANA	131	122	368	315
Segment Assets	14,997		14,997		14,616
Electric Operations
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue	704	714	1,898	1,851
Intersegment Revenue	2	2	6	7
Operating Income	257	243	588	534
Segment Assets	9,430		9,430		8,989
Gas Distribution
Segment Reporting Information [Line Items]
Intersegment Revenue	0	0	0	0
Operating Income	(6)	(7)	94	81
Regulated and Unregulated Operating Revenue	123	107	657	507
Segment Assets	2,286		2,286		2,292
Retail Gas Marketing
Segment Reporting Information [Line Items]
Intersegment Revenue	0	0	0	0
Regulated and Unregulated Operating Revenue	67	64	325	288
Income Available to Common Shareholders of SCANA	(2)	(5)	16	3
Segment Assets	131		131		153
Energy Marketing
Segment Reporting Information [Line Items]
Intersegment Revenue	44	35	133	84
Regulated and Unregulated Operating Revenue	152	151	488	402
Income Available to Common Shareholders of SCANA	1	1	5	5
Segment Assets	124		124		122
All Other [member]
Segment Reporting Information [Line Items]
Intersegment Revenue	95	100	303	309
Operating Income	8	6	22	17
Regulated and Unregulated Operating Revenue	11	11	30	32
Income Available to Common Shareholders of SCANA	(3)	(3)	(2)	(2)
Segment Assets	1,287		1,287		1,415
Adjustments/Eliminations
Segment Reporting Information [Line Items]
Intersegment Revenue	(141)	(137)	(442)	(400)
Operating Income	(4)	(4)	34	15
Regulated and Unregulated Operating Revenue	(6)	(9)	(20)	(26)
Income Available to Common Shareholders of SCANA	135	129	349	309
Segment Assets	1,739		1,739		1,645
SCEG
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue	706	716	1,903	1,857
Operating Income	255	241	625	561
Regulated Operating Revenue, Gas	70	61	297	244
Net Income (Loss) Attributable to Parent	136	129	311	272
Segment Assets	12,694		12,694		12,104
Regulated Operating Revenue	776	777	2,200	2,101
SCEG | Electric Operations
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue	706	716	1,903	1,857
Operating Income	257	244	588	534
Segment Assets	9,430		9,430		8,989
SCEG | Gas Distribution
Segment Reporting Information [Line Items]
Operating Income	(2)	(3)	37	27
Regulated Operating Revenue, Gas	70	61	297	244
Segment Assets	681		681		659
SCEG | Adjustments/Eliminations
Segment Reporting Information [Line Items]
Operating Income		0		0
Net Income (Loss) Attributable to Parent	136	129	311	272
Segment Assets	2,583		2,583		2,456
Regulated Operating Revenue		$ 0	$ 0	$ 0

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Public Utilities, Property, Plant and Equipment, Net	$ 11,582	$ 10,896
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	148	139
Allowance for Doubtful Accounts Receivable, Current	5	7
Assets, Current	1,351	1,527
Regulated Entity, Other Assets, Noncurrent	1,560	1,706
SCEG
Public Utilities, Property, Plant and Equipment, Net	10,015	9,375
Allowance for Doubtful Accounts Receivable, Current	3	3
Assets, Current	1,015	1,009
Regulated Entity, Other Assets, Noncurrent	1,496	1,566
SCEG | Variable Interest Entity, Primary Beneficiary [Member]
Public Utilities, Property, Plant and Equipment, Net	708	640
Assets, Current	162	206
Regulated Entity, Other Assets, Noncurrent	$ 43	$ 54

XML

INCOME TAXES

9 Months Ended

Sep. 30, 2013

income tax [Line Items]

Income Tax Disclosure [Text Block]

INCOME TAXES

No material changes in the status of the Company's tax positions have occurred through September 30, 2013.

During the third quarter of 2013, the State of North Carolina passed legislation that will lower the state corporate income tax rate from 6.9% to 6.0% in 2014 and 5.0% in 2015.  The change in income tax rates is not expected to have a material impact on the Company’s financial position, results of operations or cash flows. Additionally, during the third quarter of 2013, the IRS issued final regulations regarding the capitalization of certain costs for income tax purposes and re-proposed certain other related regulations (collectively referred to as tangible personal property regulations).  These regulations did not have a material impact on the Company's financial position, results of operations or cash flows.

SCEG

income tax [Line Items]

Income Tax Disclosure [Text Block]

INCOME TAXES

No material changes in the status of Consolidated SCE&G's tax positions have occurred through September 30, 2013.

During the third quarter of 2013, the IRS issued final regulations regarding the capitalization of certain costs for income tax purposes and re-proposed certain other related regulations (collectively referred to as tangible personal property regulations). These regulations did not have a material impact on Consolidated SCE&G's financial position, results of operations or cash flows.

XML

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Allowance for Funds Used During Construction, Capitalized Interest	$ 4	$ 3	$ 10	$ 8
SCEG
Allowance for Funds Used During Construction, Capitalized Interest	$ 4	$ 3	$ 9	$ 7

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Assets
Utility Plant In Service	$ 12,119	$ 11,865
Accumulated Depreciation and Amortization	(3,965)	(3,811)
Construction Work in Progress	2,558	2,084
Plant to be Retired, Net	344	362
Nuclear Fuel, Net of Accumulated Amortization	296	166
Goodwill, Net of Writedown of $230	230	230
Utility Plant, Net	11,582	10,896
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	315	306
Assets held in trust, net-nuclear decommissioning	98	94
Other investments	91	87
Nonutility Property and Investments, Net	504	487
Current Assets:
Cash and cash equivalents	30	72
Receivables, net of allowance for uncollectible accounts	710	780
Inventories (at average cost):
Fuel	263	305
Materials and supplies	145	136
Prepayments and other	194	223
Deferred income taxes	9	11
Total Current Assets	1,351	1,527
Deferred Debits and Other Assets:
Regulatory Assets, Noncurrent	1,333.0	1,464.0
Other	227	242
Total Deferred Debits and Other Assets	1,560	1,706
Total	14,997	14,616
Capitalization and Liabilities
Common equity	4,598	4,154
Long-Term Debt, Net	5,431	4,949
Total Capitalization	10,029	9,103
Current Liabilities:
Short-term borrowings	378	623
Current portion of long-term debt	19	172
Accounts payable	340	428
Customer deposits and customer prepayments	83	86
Taxes accrued	137	164
Interest accrued	75	82
Dividends declared	71	66
Derivative financial instruments	12	80
Other	88	110
Total Current Liabilities	1,203	1,811
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,723	1,653
Deferred investment tax credits	33	36
Asset retirement obligations	576	561
Pension and other postretirement benefits	263	387
Regulatory liabilities	1,007	882
Other	163	183
Total Deferred Credits and Other Liabilities	3,765	3,702
Commitments and Contingencies (Note 9)
Total	14,997	14,616
SCEG
Assets
Utility Plant In Service	10,310	10,096
Accumulated Depreciation and Amortization	(3,456)	(3,322)
Construction Work in Progress	2,521	2,073
Plant to be Retired, Net	344	362
Nuclear Fuel, Net of Accumulated Amortization	296	166
Utility Plant, Net	10,015	9,375
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	68	57
Assets held in trust, net-nuclear decommissioning	98	94
Other investments	2	3
Nonutility Property and Investments, Net	168	154
Current Assets:
Cash and cash equivalents	17	51
Receivables, net of allowance for uncollectible accounts	523	483
Due from Affiliate, Current	20	2
Inventories (at average cost):
Fuel	161	204
Materials and supplies	130	126
Prepayments and other	164	143
Total Current Assets	1,015	1,009
Deferred Debits and Other Assets:
Regulatory Assets, Noncurrent	1,259.0	1,377.0
Other	237	189
Total Deferred Debits and Other Assets	1,496	1,566
Total	12,694	12,104
Capitalization and Liabilities
Common equity	4,336	3,929
Stockholders' Equity Attributable to Noncontrolling Interest	117	114
Long-Term Debt, Net	4,043	3,557
Total Capitalization	8,496	7,600
Current Liabilities:
Short-term borrowings	310	449
Current portion of long-term debt	14	165
Accounts payable	210	281
Due to Affiliate, Current	122.0	124.0
Customer deposits and customer prepayments	53	51
Taxes accrued	158	151
Interest accrued	53	63
Dividends declared	67	46
Derivative financial instruments	2	66
Other	41	50
Total Current Liabilities	1,030	1,446
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,529	1,479
Deferred investment tax credits	33	36
Asset retirement obligations	549	535
Pension and other postretirement benefits	198	254
Regulatory liabilities	781	665
Other	78	89
Total Deferred Credits and Other Liabilities	3,168	3,058
Commitments and Contingencies (Note 9)
Total	$ 12,694	$ 12,104

XML

SEGMENT OF BUSINESS INFORMATION (Tables)

9 Months Ended

Sep. 30, 2013

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, 2013
Electric Operations	$	704		$	2		$	257		n/a
Gas Distribution	123			—			(6		)	n/a
Retail Gas Marketing	67			—			n/a			$	(2	)
Energy Marketing	152			44			n/a			1
All Other	11			95			8			(3		)
Adjustments/Eliminations	(6		)	(141		)	(4		)	135
Consolidated Total	$	1,051		$	—		$	255		$	131

Nine Months Ended September 30, 2013
Electric Operations	$	1,898		$	6		$	588	n/a
Gas Distribution	657			—			94		n/a
Retail Gas Marketing	325			—			n/a		$	16
Energy Marketing	488			133			n/a		5
All Other	30			303			22		(2		)
Adjustments/Eliminations	(20		)	(442		)	34		349
Consolidated Total	$	3,378		$	—		$	738	$	368

Three Months Ended September 30, 2012
Electric Operations	$	714		$	2		$	243		n/a
Gas Distribution	107			—			(7		)	n/a
Retail Gas Marketing	64			—			n/a			$	(5	)
Energy Marketing	151			35			n/a			1
All Other	11			100			6			(3		)
Adjustments/Eliminations	(9		)	(137		)	(4		)	129
Consolidated Total	$	1,038		$	—		$	238		$	122

Nine Months Ended September 30, 2012
Electric Operations	$	1,851		$	7		$	534	n/a
Gas Distribution	507			—			81		n/a
Retail Gas Marketing	288			—			n/a		$	3
Energy Marketing	402			84			n/a		5
All Other	32			309			17		(2		)
Adjustments/Eliminations	(26		)	(400		)	15		309
Consolidated Total	$	3,054		$	—		$	647	$	315

	September 30,		December 31,
Segment Assets	2013		2012
Electric Operations	$	9,430	$	8,989
Gas Distribution	2,286		2,292
Retail Gas Marketing	131		153
Energy Marketing	124		122
All Other	1,287		1,415
Adjustments/Eliminations	1,739		1,645
Consolidated Total	$	14,997	$	14,616

SCEG

Segment Reporting Information [Line Items]

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

.

	External		Operating			Earnings Available to
Millions of dollars	Revenue		Income			Common Shareholder
Three Months Ended September 30, 2013
Electric Operations	$	706	$	257		n/a
Gas Distribution	70		(2		)	n/a
Adjustments/Eliminations	—		—			$	136
Consolidated Total	$	776	$	255		$	136

Nine Months Ended September 30, 2013
Electric Operations	$	1,903	$	588	n/a
Gas Distribution	297		37		n/a
Adjustments/Eliminations	—		—		$	311
Consolidated Total	$	2,200	$	625	$	311

Three Months Ended September 30, 2012
Electric Operations	$	716	$	244		n/a
Gas Distribution	61		(3		)	n/a
Adjustments/Eliminations	—		—			$	129
Consolidated Total	$	777	$	241		$	129

Nine Months Ended September 30, 2012
Electric Operations	$	1,857	$	534	n/a
Gas Distribution	244		27		n/a
Adjustments/Eliminations	—		—		$	272
Consolidated Total	$	2,101	$	561	$	272

	September 30,		December 31,
Segment Assets	2013		2012
Electric Operations	$	9,430	$	8,989
Gas Distribution	681		659
Adjustments/Eliminations	2,583		2,456
Consolidated Total	$	12,694	$	12,104

XML

RATE AND OTHER REGULATORY MATTERS (Tables)

9 Months Ended

Sep. 30, 2013

Regulatory Assets

Demand reduction programs [Table Text Block]

:

Year	Effective	Amount
2013	First billing cycle of May	$16.9 million
2012	First billing cycle of May	$19.6 million

Schedule of Regulatory Assets [Table Text Block]

.

Millions of dollars	September 30, 2013		December 31, 2012
Regulatory Assets:
Accumulated deferred income taxes	$	254	$	254
Under-collections - electric fuel adjustment clause	52		66
Environmental remediation costs	42		44
AROs and related funding	359		319
Franchise agreements	32		36
Deferred employee benefit plan costs	319		460
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	126		151
Deferred pollution control costs	37		38
Unrecovered plant	19		20
Other	93		70
Total Regulatory Assets	$	1,333	$	1,464

Schedule of Regulatory Liabilities [Table Text Block]

Regulatory Liabilities:
Accumulated deferred income taxes	$	19	$	21
Asset removal costs	718		692
Storm damage reserve	27		27
Monetization of bankruptcy claim	30		32
Deferred gains on interest rate derivatives	203		110
Planned major maintenance	10		—
Total Regulatory Liabilities	$	1,007	$	882

Schedule of Changes in Electric Rate BLRA [Table Text Block]

:

Year	Action			Amount
2013	2.9	%	Increase	$67.2 million
2012	2.3	%	Increase	$52.1 million

Schedule of Changes in Gas Rate RSA [Table Text Block]

:

Year	Action			Amount
2013	No change			-
2012	2.1	%	Increase	$7.5 million

SCEG

Regulatory Assets

Demand reduction programs [Table Text Block]

Year	Effective	Amount
2013	First billing cycle of May	$16.9 million
2012	First billing cycle of May	$19.6 million

Schedule of Regulatory Assets [Table Text Block]

Millions of dollars	September 30, 2013		December 31, 2012
Regulatory Assets:
Accumulated deferred income taxes	$	248	$	248
Under collections – electric fuel adjustment clause	52		66
Environmental remediation costs	37		39
AROs and related funding	342		304
Franchise agreements	32		36
Deferred employee benefit plan costs	284		405
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	126		151
Deferred pollution control costs	37		38
Unrecovered plant	19		20
Other	82		64
Total Regulatory Assets	$	1,259	$	1,377

Schedule of Regulatory Liabilities [Table Text Block]

Regulatory Liabilities:
Accumulated deferred income taxes	$	19	$	21
Asset removal costs	522		507
Storm damage reserve	27		27
Deferred gains on interest rate derivatives	203		110
Planned major maintenance	10		—
Total Regulatory Liabilities	$	781	$	665

Schedule of Changes in Electric Rate BLRA [Table Text Block]

years indicated:

Year	Action			Amount
2013	2.9	%	Increase	$67.2 million
2012	2.3	%	Increase	$52.1 million

Schedule of Changes in Gas Rate RSA [Table Text Block]

e years indicated:

Year	Action			Amount
2013	No change			-
2012	2.1	%	Increase	$7.5 million

XML

COMMITMENTS AND CONTINGENCIES (Details) (USD $)	3 Months Ended	9 Months Ended	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2013	Dec. 31, 2005
SCEG
Nuclear Insurance
Federal Limit on Public Liability Claims from Nuclear Incident Approximate		$ 13,600,000,000
Maximum Insurance Coverage for each Nuclear Plant by ANI	375,000,000	375,000,000
Maximum liability assessment per reactor for each nuclear incident	84,800,000	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
Inflation adjustment period for nuclear insurance		5
Maximum retrospective insurance premium per nuclear incident		40,600,000
Maximum amount of coverage to nuclear facility for property damage and outage costs	2,750,000,000	2,750,000,000
Maximum amount of coverage for accidental property damage	500,000,000	500,000,000
Maximum loss covered by insurance for a single incident	2,750,000,000	2,750,000,000
Environmental
Number of MGP decommissioned sites that contain residues of byproduct chemicals		4
Site Contingency MGP Estimated Environmental Remediation Costs		21,200,000
Deferred costs net of costs previously recovered through rates and insurance settlements included in regulatory assets	37,100,000	37,100,000
Nuclear Generation
Estimated cash outflow for plant costs and related transmission infrastructure costs of nuclear electric generation site		5,700,000,000
Number of states required to reduce emissions to attain mandated levels			28
Estimated Delay costs related to New Units		200,000,000
Est Delay cost for new unit		$ 200,000,000
PSNC Energy
Environmental
Number of MGP sites requiring cleanup		5

XML

DERIVATIVE FINANCIAL INSTRUMENTS (Details 2) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	$ (3,000,000)		$ (3,000,000)		$ (17,000,000)
Asset Derivatives Fair Value	135,000,000		135,000,000		88,000,000
Derivative Asset	135,000,000		135,000,000		87,000,000
Derivative Asset, Fair Value, Gross Liability					(1,000,000)
Liability Derivatives Fair Value	37,000,000		37,000,000		123,000,000
Derivative Liability Fair Value Gross Amount Offset in the Statement of Financial Position	0		0		(1,000,000)
Derivative Liability	37,000,000		37,000,000		122,000,000
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(3,000,000)		(3,000,000)		(17,000,000)
Derivative Liability, Fair Value of Collateral	30,000,000		30,000,000		78,000,000
Net Fair Value Derivative Asset offset against Collateral	132,000,000		132,000,000		70,000,000
Net Fair Value Derivative Liability offset against Collateral	4,000,000		4,000,000		27,000,000
Prepayments and other current assets [member]
Derivative [Line Items]
Derivative Asset	89,000,000		89,000,000		50,000,000
Derivative Liability	1,000,000		1,000,000
Other current liabilities
Derivative [Line Items]
Derivative Liability	12,000,000		12,000,000		80,000,000
Other deferred credits and other liabilities
Derivative [Line Items]
Derivative Liability	24,000,000		24,000,000		42,000,000
Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	46,000,000		46,000,000		37,000,000
Derivatives designated as hedging instruments
Derivative [Line Items]
Asset Derivatives Fair Value	124,000,000		124,000,000		74,000,000
Liability Derivatives Fair Value	27,000,000		27,000,000		110,000,000
Derivatives not designated as hedging instruments
Derivative [Line Items]
Asset Derivatives Fair Value	11,000,000		11,000,000		14,000,000
Liability Derivatives Fair Value	10,000,000		10,000,000		13,000,000
Energy Management Contracts [Member]
Derivative [Line Items]
Asset Derivatives Fair Value	10,000,000		10,000,000		13,000,000
Derivative Asset	10,000,000		10,000,000		12,000,000
Derivative Asset, Fair Value, Gross Liability					(1,000,000)
Liability Derivatives Fair Value	10,000,000		10,000,000		13,000,000
Derivative Liability Fair Value Gross Amount Offset in the Statement of Financial Position	0		0		(1,000,000)
Derivative Liability	10,000,000		10,000,000		12,000,000
Derivative Liability, Fair Value of Collateral	(8,000,000)		(8,000,000)		(11,000,000)
Net Fair Value Derivative Asset offset against Collateral	10,000,000		10,000,000		12,000,000
Net Fair Value Derivative Liability offset against Collateral	2,000,000		2,000,000		1,000,000
Interest Rate Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income Effective Portion, Net	(1,000,000)	(1,000,000)	(2,000,000)	(2,000,000)
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	(3,000,000)		(3,000,000)		(17,000,000)
Asset Derivatives Fair Value	124,000,000		124,000,000		73,000,000
Derivative Asset	124,000,000		124,000,000		73,000,000
Liability Derivatives Fair Value	24,000,000		24,000,000		106,000,000
Derivative Liability	24,000,000		24,000,000		106,000,000
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(3,000,000)		(3,000,000)		(17,000,000)
Derivative Liability, Fair Value of Collateral	(21,000,000)		(21,000,000)		(67,000,000)
Net Fair Value Derivative Asset offset against Collateral	121,000,000		121,000,000		56,000,000
Net Fair Value Derivative Liability offset against Collateral	0		0		22,000,000
Interest Rate Contract | Derivatives designated as hedging instruments | Prepayments and other current assets [member]
Derivative [Line Items]
Asset Derivatives Fair Value	83,000,000		83,000,000		42,000,000
Interest Rate Contract | Derivatives designated as hedging instruments | Other current liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	5,000,000		5,000,000		70,000,000
Interest Rate Contract | Derivatives designated as hedging instruments | Other deferred credits and other liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	19,000,000		19,000,000		36,000,000
Interest Rate Contract | Derivatives designated as hedging instruments | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Asset Derivatives Fair Value	41,000,000		41,000,000		31,000,000
Commodity Contract
Derivative [Line Items]
Asset Derivatives Fair Value	1,000,000		1,000,000		2,000,000
Derivative Asset	1,000,000		1,000,000		2,000,000
Liability Derivatives Fair Value	3,000,000		3,000,000		4,000,000
Derivative Liability	3,000,000		3,000,000		4,000,000
Derivative Liability, Fair Value of Collateral	(1,000,000)		(1,000,000)
Net Fair Value Derivative Asset offset against Collateral	1,000,000		1,000,000		2,000,000
Net Fair Value Derivative Liability offset against Collateral	2,000,000		2,000,000		4,000,000
Commodity Contract | Derivatives designated as hedging instruments | Prepayments and other current assets [member]
Derivative [Line Items]
Asset Derivatives Fair Value					1,000,000
Commodity Contract | Derivatives designated as hedging instruments | Other current liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	3,000,000		3,000,000		4,000,000
Commodity Contract | Derivatives not designated as hedging instruments | Prepayments and other current assets [member]
Derivative [Line Items]
Asset Derivatives Fair Value	1,000,000		1,000,000		1,000,000
Other Energy Management Contract [Member] | Derivatives not designated as hedging instruments | Prepayments and other current assets [member]
Derivative [Line Items]
Asset Derivatives Fair Value	5,000,000		5,000,000		7,000,000
Liability Derivatives Fair Value	1,000,000		1,000,000		1,000,000
Other Energy Management Contract [Member] | Derivatives not designated as hedging instruments | Other current liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	4,000,000		4,000,000		6,000,000
Other Energy Management Contract [Member] | Derivatives not designated as hedging instruments | Other deferred credits and other liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	5,000,000		5,000,000
Other Energy Management Contract [Member] | Derivatives not designated as hedging instruments | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Asset Derivatives Fair Value	5,000,000		5,000,000		6,000,000
Liability Derivatives Fair Value					6,000,000
SCEG
Derivative [Line Items]
Derivative Asset	124,000,000		124,000,000		73,000,000
Derivative Liability	3,000,000		3,000,000		75,000,000
SCEG | Prepayments and other current assets [member]
Derivative [Line Items]
Derivative Asset	83,000,000		83,000,000		42,000,000
SCEG | Other current liabilities
Derivative [Line Items]
Derivative Liability	2,000,000		2,000,000		66,000,000
SCEG | Other deferred credits and other liabilities
Derivative [Line Items]
Derivative Liability	1,000,000		1,000,000		9,000,000
SCEG | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Derivative Asset	41,000,000		41,000,000		31,000,000
SCEG | Derivatives designated as hedging instruments
Derivative [Line Items]
Asset Derivatives Fair Value	124,000,000		124,000,000		73,000,000
Liability Derivatives Fair Value	3,000,000		3,000,000		75,000,000
SCEG | Interest Rate Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income Effective Portion, Net	(1,000,000)	(1,000,000)	(2,000,000)	(2,000,000)
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	(3,000,000)		(3,000,000)		(17,000,000)
Asset Derivatives Fair Value	124,000,000		124,000,000		73,000,000
Derivative Asset	124,000,000		124,000,000		73,000,000
Liability Derivatives Fair Value	3,000,000		3,000,000		75,000,000
Derivative Liability	3,000,000		3,000,000		75,000,000
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(3,000,000)		(3,000,000)		(17,000,000)
Derivative Liability, Fair Value of Collateral	0		0		35,000,000
Net Fair Value Derivative Asset offset against Collateral	121,000,000		121,000,000		56,000,000
Net Fair Value Derivative Liability offset against Collateral	0		0		23,000,000
SCEG | Interest Rate Contract | Derivatives designated as hedging instruments | Prepayments and other current assets [member]
Derivative [Line Items]
Asset Derivatives Fair Value	83,000,000		83,000,000		42,000,000
SCEG | Interest Rate Contract | Derivatives designated as hedging instruments | Other current liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	2,000,000		2,000,000		66,000,000
SCEG | Interest Rate Contract | Derivatives designated as hedging instruments | Other deferred credits and other liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	1,000,000		1,000,000		9,000,000
SCEG | Interest Rate Contract | Derivatives designated as hedging instruments | Other Deferred Debits and Other Assets [Member]
Derivative [Line Items]
Asset Derivatives Fair Value	$ 41,000,000		$ 41,000,000		$ 31,000,000

XML

LONG-TERM AND SHORT-TERM DEBT (Details) (USD $) In Millions, unless otherwise specified								9 Months Ended							3 Months Ended		3 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013 SCE&G (including Fuel Company)	May 01, 2013 SCE&G (including Fuel Company)	Dec. 31, 2012 SCE&G (including Fuel Company)	Oct. 15, 2012 SCE&G (including Fuel Company)	Sep. 30, 2012 SCE&G (including Fuel Company)	Sep. 30, 2013 SCEG	Dec. 31, 2012 SCEG	Sep. 30, 2012 SCEG	Mar. 31, 2013 Fuel Company	Sep. 30, 2012 Fuel Company	Sep. 30, 2013 Bonds [Member]	Jan. 31, 2013 Bonds [Member]	Mar. 31, 2013 Industrial Revenue Bonds issued by JEDA proceeds of which were loaned to subsidiary	Jan. 31, 2013 Industrial Revenue Bonds issued by JEDA proceeds of which were loaned to subsidiary	Mar. 31, 2013 Industrial and Pollution Control Bonds [Member]	Jan. 31, 2013 Industrial and Pollution Control Bonds [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of First Mortgage Bond								$ 400
Debt Instrument, Increase, Additional Borrowings															39.5		14.7
Debt Instrument, Interest Rate, Stated Percentage													4.60%	7.125%	3.63%	4.00%		5.20%
Debt Instrument, Decrease, Repayments																	56.9
Line of Credit Facility, Maximum Borrowing Capacity	1,800		1,400	200	1,400	1,400	1,200			1,200	500	500
Commercial Paper			310		449
Debt, Weighted Average Interest Rate			0.30%		0.42%
Letters of Credit Outstanding, Amount			0.3		0.3
Line of Credit Facility, Remaining Borrowing Capacity			1,090		951
Long-term Debt, Current Maturities	19	172						14	165
Long- Term Debt Noncurrent including Derivative Liabilities	5,431	4,949						4,043	3,557
Debt Instrument, Face Amount								$ 67.8

XML

LONG-TERM AND SHORT-TERM DEBT (Details 2) (USD $) In Millions, unless otherwise specified																	9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Oct. 15, 2012	Sep. 30, 2013 Wells Fargo Bank, National Association (Member)	Sep. 30, 2013 Bank of America, N.A. (Member)	Sep. 30, 2013 Morgan Stanly Bank, N.A. (Member)	Sep. 30, 2013 Branch Banking and Trust Company (Member)	Sep. 30, 2013 Credit Suisse AG, Cayman Islands Branch (Member)	Sep. 30, 2013 JPMorgan Chase Bank, N.A. (Member)	Sep. 30, 2013 Mizuho Corporate Bank, Ltd (Member)	Sep. 30, 2013 TD Bank, N.A. (Member)	Sep. 30, 2013 UBS Loan Finance LLC (Member)	Sep. 30, 2013 Deutsche Bank AG New York Branch [Member] [Member]	Sep. 30, 2013 Union Bank, N.A. (Member)	Sep. 30, 2013 US Bank National Association (Member)	Sep. 30, 2013 Two other banks [Domain]	Sep. 30, 2013 SCEG	Dec. 31, 2012 SCEG	Oct. 15, 2012 SCEG	Sep. 30, 2012 SCEG	Sep. 30, 2013 SCEG Wells Fargo Bank, National Association (Member)	Sep. 30, 2013 SCEG Bank of America, N.A. (Member)	Sep. 30, 2013 SCEG Morgan Stanly Bank, N.A. (Member)	Sep. 30, 2013 SCEG Branch Banking and Trust Company (Member)	Sep. 30, 2013 SCEG Credit Suisse AG, Cayman Islands Branch (Member)	Sep. 30, 2013 SCEG JPMorgan Chase Bank, N.A. (Member)	Sep. 30, 2013 SCEG Mizuho Corporate Bank, Ltd (Member)	Sep. 30, 2013 SCEG TD Bank, N.A. (Member)	Sep. 30, 2013 SCEG UBS Loan Finance LLC (Member)	Sep. 30, 2013 SCEG Deutsche Bank AG New York Branch [Member] [Member]	Sep. 30, 2013 SCEG Union Bank, N.A. (Member)	Sep. 30, 2013 SCEG US Bank National Association (Member)	Sep. 30, 2013 SCEG Two other banks [Domain]	Sep. 30, 2013 Parent Company [Member]	Dec. 31, 2012 Parent Company [Member]	Sep. 30, 2012 Parent Company [Member]	Sep. 30, 2013 Retail Gas Marketing and Energy Marketing	Dec. 31, 2012 Retail Gas Marketing and Energy Marketing	Sep. 30, 2013 SCE&G (including Fuel Company)	May 01, 2013 SCE&G (including Fuel Company)	Dec. 31, 2012 SCE&G (including Fuel Company)	Oct. 15, 2012 SCE&G (including Fuel Company)	Sep. 30, 2012 SCE&G (including Fuel Company)	Sep. 30, 2013 SCE&G (including Fuel Company) Wells Fargo Bank, National Association (Member)	Sep. 30, 2013 SCE&G (including Fuel Company) Branch Banking and Trust Company (Member)	Sep. 30, 2013 SCE&G (including Fuel Company) Credit Suisse AG, Cayman Islands Branch (Member)	Mar. 31, 2013 Fuel Company	Sep. 30, 2012 Fuel Company	Sep. 30, 2013 PSNC Energy	Dec. 31, 2012 PSNC Energy	Sep. 30, 2012 PSNC Energy	Sep. 30, 2013 Bonds [Member]	Jan. 31, 2013 Bonds [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of First Mortgage Bond																	$ 400
Repayments of First Mortgage Bond																	150
Due to Affiliate, Current																	122.0	124.0																			13.2	13.1
Debt Instruments [Abstract]
Debt Instrument, Interest Rate, Stated Percentage																																																				4.60%	7.125%
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	1,800																			1,200														300	300	300			1,400	200	1,400	1,400	1,200				500	500	100	100	100
Commercial Paper																																		68	142				310		449								0	32
Commercial paper, weighted average interest rate (as a percent)																																		0.427%	0.58%				0.30%		0.42%								0.00%	0.44%
Letters of credit supported by LOC																																		3.0	3.0				0.3		0.3								0	0
Line of Credit Facility, Remaining Borrowing Capacity																																		229	155				1,090		951								100	68
LOC advances																																		0	0				0		0								0	0
3 year credit agreement																		200
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				10.70%	10.70%	10.70%	8.90%	8.90%	8.90%	8.90%	8.90%	8.90%	6.30%	6.30%	6.30%	6.00%					10.70%	10.70%	10.70%	8.90%	8.90%	8.90%	8.90%	8.90%	8.90%	6.30%	6.30%	6.30%	6.00%											10.70%	6.30%	8.90%
Number of other banks (in entities)			2																2
Related Party Transaction, Due from (to) Related Party, Current	$ 39.6	$ 49.4

XML

LONG-TERM AND SHORT-TERM DEBT

9 Months Ended

Sep. 30, 2013

Debt Instrument [Line Items]

Long-term Debt [Text Block]

LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

In June 2013, SCE&G issued $400 million of 4.60% first mortgage bonds due June 15, 2043. Proceeds from this sale were used to pay at maturity $150 million of its 7.125% first mortgage bonds due June 15, 2013, 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 January 2013, JEDA issued at a premium, for the benefit of SCE&G, $39.5 million of 4.0% tax-exempt industrial revenue bonds due February 1, 2028, and $14.7 million of 3.63% tax-exempt industrial revenue bonds due February 1, 2033. Proceeds from these sales were loaned by JEDA to SCE&G and, together with other available funds, were used to redeem prior to maturity $56.9 million of 5.2% industrial revenue bonds due November 1, 2027.

Substantially all of SCE&G’s and GENCO’s electric utility plant is pledged as collateral in connection with long-term debt. The Company is in compliance with all debt covenants.

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, 2013			December 31, 2012			September 30, 2013			December 31, 2012			September 30, 2013		December 31, 2012
Lines of credit:
Total committed long-term	$	300		$	300		$	1,400		$	1,400		$	100	$	100
LOC advances	—			—			—			—			—		—
Weighted average interest rate	—			—			—			—			—		—
Outstanding commercial paper (270 or fewer days)	$	68		$	142		$	310		$	449		—		$	32
Weighted average interest rate	0.43		%	0.58		%	0.30		%	0.42		%	—		0.44		%
Letters of credit supported by LOC	$	3		$	3		$	0.3		$	0.3		—		—
Available	$	229		$	155		$	1,090		$	951		$	100	$	68

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. In addition, SCE&G is party to a three-year credit agreement in the amount of $200 million. In October 2013, the term of each of these credit agreements was extended by one year, such that the five-year agreements expire in October 2018, and the three-year agreement 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 Branch Banking and Trust Company.  The letters of credit expire, subject to renewal, in the fourth quarter of 2014.

SCEG

Debt Instrument [Line Items]

Long-term Debt [Text Block]

LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

In June 2013, SCE&G issued $400 million of 4.60% first mortgage bonds due June 15, 2043. Proceeds from this sale were used to pay at maturity $150 million of its 7.125% first mortgage bonds due June 15, 2013, 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 January 2013, JEDA issued at a premium, for the benefit of SCE&G, $39.5 million of 4.0% tax-exempt industrial revenue bonds due February 1, 2028, and $14.7 million of 3.63% tax-exempt industrial revenue bonds due February 1, 2033. Proceeds from these sales were loaned by JEDA to SCE&G and, together with other available funds, were used to redeem prior to maturity $56.9 million of 5.2% industrial revenue bonds due November 1, 2027.

 Substantially all of Consolidated SCE&G’s electric utility plant is pledged as collateral in connection with long-term debt. Consolidated SCE&G is in compliance with all debt covenants.

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, 2013			December 31, 2012
Lines of credit:
Total committed long-term	$	1,400		$	1,400
LOC advances	—			—
Weighted average interest rate	—			—
Outstanding commercial paper (270 or fewer days)	$	310		$	449
Weighted average interest rate	0.30		%	0.42		%
Letters of credit supported by LOC	$	0.3		$	0.3
Available	$	1,090		$	951

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). In addition, SCE&G is party to a three-year credit agreement in the amount of $200 million. In October 2013, the term of each of these credit agreements was extended by one year, such that the five-year agreements will expire in October 2018, and the three-year agreement 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 Branch Banking and Trust Company.  The letters of credit expire, subject to renewal, in the fourth quarter of 2014.

Consolidated SCE&G participates in a utility money pool. Money pool borrowings and investments bear interest at short-term market rates. Consolidated SCE&G’s interest income and expense from money pool transactions was not significant for any period presented. At September 30, 2013 and December 31, 2012, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $39.6 million and $49.4 million, respectively.

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012	Dec. 31, 2013 SCEG MW	Sep. 30, 2013 SCEG MW	Mar. 31, 2013 SCEG	Dec. 31, 2012 SCEG MW	Sep. 30, 2013 Genco MW
Significant Accounting Policies
Number of coal fired units to be retired							2	6	6
Power Generation Capacity Megawatts										605
Asset Management and Supply Service Agreements
Percentage of natural gas inventory held by counterparties under asset management and supply service agreements (as a percent)	47.00%		47.00%		44.00%
Natural gas inventory, carrying amount	$ 23.2		$ 23.2		$ 19.6
Property, Plant and Equipment, Net	$ 315		$ 315		$ 306		$ 68		$ 57	$ 478
Power generation capacity six coal fired units							730
Power Capacity of Retired Unit									90
Power Capacity of unit to be retired						295
Earnings Per Share
Weighted Average Shares Outstanding - Basic	140.1	131.4	138.0	130.8
Incremental Common Shares Attributable to Share-based Payment Arrangements and Equity Forward Agreements	0	2.4	0.6	2.3
Weighted Average Number of Shares Outstanding, Diluted	140.1	133.8	138.6	133.1

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details 2) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Carrying Amount
Financial instruments for which the carrying amount may not equal estimated fair value
Long-term debt	$ 5,450.9	$ 5,121.0
Estimated Fair Value
Financial instruments for which the carrying amount may not equal estimated fair value
Long-term debt	5,936.7	6,115.0
SCEG | Carrying Amount
Financial instruments for which the carrying amount may not equal estimated fair value
Long-term debt	4,056.4	3,722.0
SCEG | Estimated Fair Value
Financial instruments for which the carrying amount may not equal estimated fair value
Long-term debt	$ 4,454.4	$ 4,543.1

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

9 Months Ended

Sep. 30, 2013

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

		Fair Value Measurements Using
		Quoted Prices in
		Active Markets for		Significant Other
		Identical Assets		Observable Inputs
Millions of dollars		(Level 1)		(Level 2)
As of September 30, 2013
Assets -	Available for sale securities	$	9	—
	Interest rate contracts	—		$	124
	Commodity contracts	1		—
	Energy management contracts	—		10
Liabilities -	Interest rate contracts	—		24
	Commodity contracts	—		3
	Energy management contracts	—		13
As of December 31, 2012
Assets -	Available for sale securities	$	6	—
	Interest rate contracts	—		$	73
	Commodity contracts	1		1
	Energy management contracts	—		13
Liabilities -	Interest rate contracts	—		106
	Commodity contracts	—		4
	Energy management contracts	1		15

There were no fair value measurements based on significant unobservable inputs (Level 3) for either period presented.  In addition, 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 at September 30, 2013 and December 31, 2012 were as follows:

	September 30, 2013				December 31, 2012
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	5,450.9	$	5,936.7	$	5,121.0	$	6,115.0

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 measurements based on significant other observable inputs (level 2) were as follows: 

		Fair Value Measurements Using Significant
		Other Observable Inputs (Level 2)
Millions of dollars		September 30, 2013		December 31, 2012
Assets -	Interest rate contracts	$	124	$	73
Liabilities -	Interest rate contracts	3		75

There were no fair value measurements based on quoted prices in active markets for identical assets (Level 1) or significant unobservable inputs (Level 3) for either period presented.  In addition, 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 at September 30, 2013 and December 31, 2012 were as follows:

	September 30, 2013				December 31, 2012
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	4,056.4	$	4,454.4	$	3,722.0	$	4,543.1

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

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

XML

COMMON EQUITY

9 Months Ended

Sep. 30, 2013

Stockholders' Equity Note [Abstract]

COMMON EQUITY

COMMON EQUITY

Changes in common equity during the nine months ended September 30, 2013 and 2012 were as follows:

Millions of dollars	2013			2012
Balance at January 1,	$	4,154		$	3,889
Common stock issued	273			73
Dividends declared	(212		)	(194		)
Comprehensive income	383			327
Balance as of September 30,	$	4,598		$	4,095

SCANA had 200 million shares of common stock authorized as of September 30, 2013 and December 31, 2012, of which 140.2 million and 132.0 million were issued and outstanding at September 30, 2013 and December 31, 2012, respectively.

On March 5, 2013, SCANA settled all forward sales contracts related to its common stock through the issuance of approximately 6.6 million common shares, resulting in net proceeds of approximately $196.2 million.

Reclassifications of gains (losses) from AOCI into earnings, net of taxes, were as follows:

Millions of dollars	2013			2012			Income Statement Line Item Affected
Three months ended September 30,
Interest rate contracts	$	(2	)	$	(2	)	Increase in interest expense
Commodity contracts	—			(1		)	Increase in gas purchased for resale
Deferred employee benefit plan costs	(1		)	—
Total reclassifications	$	(3	)	$	(3	)
Nine months ended September 30,
Interest rate contracts	$	(5	)	$	(5	)	Increase in interest expense
Commodity contracts	(2		)	(12		)	Increase in gas purchased for resale
Deferred employee benefit plan costs	(1		)	(1		)
Total reclassifications	$	(8	)	$	(18	)

For information related to the reclassification of deferred employee benefit amounts from AOCI, see Note 8.

SCEG

Stockholders' Equity Note [Abstract]

COMMON EQUITY

EQUITY

Changes in common equity during the nine months ended September 30, 2013 and 2012 were as follows:

Millions of dollars	Common Equity			Noncontrolling Interest			Total Equity
Balance at January 1, 2013	$	3,929		$	114		$	4,043
Capital contribution from parent	285			—			285
Dividends declared	(190		)	(5		)	(195		)
Comprehensive income	312			8			320
Balance as of September 30, 2013	$	4,336		$	117		$	4,453
Balance at January 1, 2012	$	3,665		$	108		$	3,773
Capital contribution from parent	84			—			84
Dividends declared	(157		)	(5		)	(162		)
Comprehensive income	272			9			281
Balance as of September 30, 2012	$	3,864		$	112		$	3,976

SCE&G had 50 million shares of common stock authorized as of September 30, 2013 and December 31, 2012, of which 40.3 million were issued and outstanding during all periods presented. SCE&G had 20 million shares of preferred stock authorized as of September 30, 2013 and December 31, 2012, of which 1,000 shares 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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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss), Net of Tax	$ 69.9		$ 69.9		$ 85.6
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	0	0	2	(4)
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Tax	1	2	4	11
Other Comprehensive (Income) Loss, Pension and Other Postretirment Benefit Plans, Remeasurement and Curtailment Adjustment, Tax	2	0	2	0
SCEG
Accumulated Other Comprehensive Income (Loss), Net of Tax	$ 2.7		$ 2.7		$ 4.0

XML

RATE AND OTHER REGULATORY MATTERS (Details 3) (USD $)	3 Months Ended		9 Months Ended		12 Months Ended	24 Months Ended
	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2013 MW	Sep. 30, 2012	Dec. 31, 2012	Jul. 31, 2012	May 15, 2014	Oct. 01, 2013	Jun. 30, 2012
Regulatory Liabilities:
MPG enviromental remediatio			26
Regulatory liabilities		$ 882,000,000	$ 1,007,000,000		$ 882,000,000
Amount allowed to be recovered through electric rates to offset incremental storm damage costs			0
Annual amount of storm damage costs which can not be offset by amounts recovered through electric rates			2.5
Accrual period of nuclear refueling charges in months			18
Regulatory Noncurrent Asset Amortization Period			30
Deferred Income Tax Charges [Member]
Regulatory Liabilities:
Regulatory liabilities		21,000,000	19,000,000		21,000,000
Asset Retirement Obligation Costs [Member]
Regulatory Liabilities:
Regulatory liabilities		692,000,000	718,000,000		692,000,000
Storm damage reserve
Regulatory Liabilities:
Regulatory liabilities		27,000,000	27,000,000		27,000,000
Monetization bankruptcy claim [Member]
Regulatory Liabilities:
Regulatory liabilities		32,000,000	30,000,000		32,000,000
Deferred gains on interest rate derivatives
Regulatory Liabilities:
Regulatory liabilities		110,000,000	203,000,000		110,000,000
Planned major maintenance [Member]
Regulatory Liabilities:
Regulatory liabilities		0	10,000,000		0
SCEG
Regulatory Liabilities:
Undercollected balance fuel									80,600,000
Public Utilities Property Plant and Equipment Identifiable Capital Costs					278,000,000
Capital Cost Related to New Federal Healthcare Etc					1,000,000
Public Utilities, Percent Increase (Decrease) in Retail Electric Rates		4.23%		2.90%	2.30%
Public Utilities, Authorized Allowable Return on Common Equity, Percentage		10.25%	11.00%
historical average temperature					15
Power generation capacity six coal fired units			730
Demand Side Management Program Costs, Noncurrent		19,600,000	16,900,000		19,600,000		10,300,000
Regulatory liabilities		665,000,000	781,000,000		665,000,000
Amount allowed to be recovered through electric rates to offset incremental storm damage costs			100,000,000
Annual amount of storm damage costs which can not be offset by amounts recovered through electric rates			2,500,000
Accrual period of nuclear refueling charges in months	18
Regulatory Noncurrent Asset Amortization Period			30
Amounts Recovered through Electric Rates to offset Turbine Expense						18,400,000
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority		63,000,000			63,000,000			14,000,000
Share in Approved Capital Costs					8,000,000
Public Utilities Additional Labor Expenses for Oversight of New Units					$ 132,000,000

XML

SEGMENT OF BUSINESS INFORMATION

9 Months Ended

Sep. 30, 2013

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 equity method investments and other nonreportable segments.  Nonreportable segments include a FERC-regulated interstate pipeline company and other companies that conduct nonregulated operations in energy-related and telecommunications industries.

Millions of dollars	External Revenue			Intersegment Revenue			Operating Income			Net Income
Three Months Ended September 30, 2013
Electric Operations	$	704		$	2		$	257		n/a
Gas Distribution	123			—			(6		)	n/a
Retail Gas Marketing	67			—			n/a			$	(2	)
Energy Marketing	152			44			n/a			1
All Other	11			95			8			(3		)
Adjustments/Eliminations	(6		)	(141		)	(4		)	135
Consolidated Total	$	1,051		$	—		$	255		$	131

Nine Months Ended September 30, 2013
Electric Operations	$	1,898		$	6		$	588	n/a
Gas Distribution	657			—			94		n/a
Retail Gas Marketing	325			—			n/a		$	16
Energy Marketing	488			133			n/a		5
All Other	30			303			22		(2		)
Adjustments/Eliminations	(20		)	(442		)	34		349
Consolidated Total	$	3,378		$	—		$	738	$	368

Three Months Ended September 30, 2012
Electric Operations	$	714		$	2		$	243		n/a
Gas Distribution	107			—			(7		)	n/a
Retail Gas Marketing	64			—			n/a			$	(5	)
Energy Marketing	151			35			n/a			1
All Other	11			100			6			(3		)
Adjustments/Eliminations	(9		)	(137		)	(4		)	129
Consolidated Total	$	1,038		$	—		$	238		$	122

Nine Months Ended September 30, 2012
Electric Operations	$	1,851		$	7		$	534	n/a
Gas Distribution	507			—			81		n/a
Retail Gas Marketing	288			—			n/a		$	3
Energy Marketing	402			84			n/a		5
All Other	32			309			17		(2		)
Adjustments/Eliminations	(26		)	(400		)	15		309
Consolidated Total	$	3,054		$	—		$	647	$	315

	September 30,		December 31,
Segment Assets	2013		2012
Electric Operations	$	9,430	$	8,989
Gas Distribution	2,286		2,292
Retail Gas Marketing	131		153
Energy Marketing	124		122
All Other	1,287		1,415
Adjustments/Eliminations	1,739		1,645
Consolidated Total	$	14,997	$	14,616

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.

	External		Operating			Earnings Available to
Millions of dollars	Revenue		Income			Common Shareholder
Three Months Ended September 30, 2013
Electric Operations	$	706	$	257		n/a
Gas Distribution	70		(2		)	n/a
Adjustments/Eliminations	—		—			$	136
Consolidated Total	$	776	$	255		$	136

Nine Months Ended September 30, 2013
Electric Operations	$	1,903	$	588	n/a
Gas Distribution	297		37		n/a
Adjustments/Eliminations	—		—		$	311
Consolidated Total	$	2,200	$	625	$	311

Three Months Ended September 30, 2012
Electric Operations	$	716	$	244		n/a
Gas Distribution	61		(3		)	n/a
Adjustments/Eliminations	—		—			$	129
Consolidated Total	$	777	$	241		$	129

Nine Months Ended September 30, 2012
Electric Operations	$	1,857	$	534	n/a
Gas Distribution	244		27		n/a
Adjustments/Eliminations	—		—		$	272
Consolidated Total	$	2,101	$	561	$	272

	September 30,		December 31,
Segment Assets	2013		2012
Electric Operations	$	9,430	$	8,989
Gas Distribution	681		659
Adjustments/Eliminations	2,583		2,456
Consolidated Total	$	12,694	$	12,104

XML

DERIVATIVE FINANCIAL INSTRUMENTS

9 Months Ended

Sep. 30, 2013

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 other comprehensive income (loss) 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 the Audit Committee's 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.  In cases in which 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 lock or forward starting swap agreements that are designated as cash flow hedges.  Except as described in the following paragraph, the effective portions of changes in fair value and payments made or received upon termination of such agreements for regulated subsidiaries are recorded in regulatory assets or regulatory liabilities. For 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 authorization granted in October 2013, certain interest rate derivatives entered into by SCE&G will no longer be designated as cash flow hedges, and fair value changes and settlement amounts are to be recorded in its regulatory asset and liability accounts. Upon settlement, losses on swaps will be amortized over the lives of related debt issuances, and gains may be applied to undercollected fuel amounts or may be amortized to interest expense as 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, 2013
Commodity	8,820,000	10,407,000	3,078,500	22,305,500
Energy Management (a)	—	—	30,908,058	30,908,058
Total (a)	8,820,000	10,407,000	33,986,558	53,213,558
As of December 31, 2012
Commodity	5,170,000	6,490,000	4,877,000	16,537,000
Energy Management (b)	—	—	31,763,275	31,763,275
Total (b)	5,170,000	6,490,000	36,640,275	48,300,275

(a)  Includes an aggregate 674,308 MMBTU related to basis swap contracts in Energy Marketing.

(b)  Includes an aggregate 3,500,000 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 $663.8 million at September 30, 2013 and $1.1 billion at December 31, 2012.

The fair value of energy-related derivatives and interest rate derivatives was reflected in the condensed consolidated balance sheet as follows:

	Fair Values of Derivative Instruments
	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
Millions of dollars	Location	Value		Location	Value
As of September 30, 2013
Derivatives designated as hedging instruments
Interest rate	Prepayments and other	$	83	Other current liabilities	$	5
	Other deferred debits and other assets	41		Other deferred credits and other liabilities	19
Commodity				Other current liabilities	3
Total		$	124		$	27
Derivatives not designated as hedging instruments
Commodity	Prepayments and other	$	1
Energy Management	Prepayments and other	5		Prepayments and other	$	1
				Other current liabilities	4
	Other deferred debits and other assets	5		Other deferred credits and other liabilities	5
Total		$	11		$	10

As of December 31, 2012
Derivatives designated as hedging instruments
Interest rate	Prepayments and other	$	42	Other current liabilities	$	70
	Other deferred debits and other assets	31		Other deferred credits and other liabilities	36
Commodity	Prepayments and other	1		Other current liabilities	4
Total		$	74		$	110
Derivatives not designated as hedging instruments
Commodity	Prepayments and other	$	1
Energy management	Prepayments and other	7		Prepayments and other	$	1
	Other deferred debits and other assets	6		Other current liabilities	6
				Other deferred debits and other assets	6
Total		$	14		$	13

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

Fair Value Hedges

With regard to the Company's interest rate swaps designated as fair value hedges, any gains or losses related to the swaps or the fixed rate debt are recognized in current earnings and included in interest expense.  The Company had no interest rate swaps designated as fair value hedges for any period presented, and the amortization of deferred gains on previously terminated swaps were not significant during any period presented.

Cash Flow Hedges

Derivatives in Cash Flow Hedging Relationships

	Gain Deferred in Regulatory Accounts					Loss Reclassified from Deferred Accounts into Income
Millions of dollars	(Effective Portion)					(Effective Portion)
September 30,	2013		2012		Location	2013			2012
Three Months Ended
Interest rate	$	19	$	23	Interest expense	$	(1	)	$	(1	)
Nine Months Ended
Interest rate	$	115	$	51	Interest expense	$	(2	)	$	(2	)

	Gain (Loss) Recognized in OCI, net of tax							Loss Reclassified from AOCI into Income, net of tax
Millions of dollars	(Effective Portion)							(Effective Portion)
September 30,	2013			2012			Location	2013			2012
Three Months Ended
Interest rate	—			$	(1	)	Interest expense	$	(2	)	$	(2	)
Commodity	$	(1	)	2			Gas purchased for resale	—			(1		)
Total	$	(1	)	$	1			$	(2	)	$	(3	)
Nine Months Ended
Interest rate	$	4		$	(5	)	Interest expense	$	(5	)	$	(5	)
Commodity	(1		)	(1		)	Gas purchased for resale	(2		)	(12		)
Total	$	3		$	(6	)		$	(7	)	$	(17	)

As of September 30, 2013, the Company expects that during the next 12 months reclassifications from accumulated other comprehensive income (loss) to earnings arising from cash flow hedges will include approximately $2.0 million as an increase to gas cost and approximately $6.2 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels.  As of September 30, 2013, all of the Company’s commodity cash flow hedges settle by their terms before the end of 2015.

Derivatives not designated as Hedging Instruments		Loss Recognized in Income
Millions of dollars	Location	2013	2012
Three Months Ended September 30,
Commodity	Gas purchased for resale	—	—
Nine Months Ended September 30,
Commodity	Gas purchased for resale	—	$	(1	)

Hedge Ineffectiveness

Other losses recognized in income representing ineffectiveness on interest rate hedges designated as cash flow hedges were insignificant in each of the three and nine months ended September 30, 2013 and 2012, respectively.

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 on an ongoing basis. 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, 2013 and December 31, 2012, the Company has posted $35.4 million and $78.3 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 Prepayments and other on the consolidated balance sheets. Collateral related to noncurrent positions is recorded in Other within Deferred Debits and Other Assets on the consolidated balance sheets. If all of the contingent features underlying these instruments had been fully triggered as of September 30, 2013 and December 31, 2012, the Company could have been required to post an additional $- million and $26.2 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, 2013 and December 31, 2012 is $35.3 million and $104.5 million, respectively.

In addition, as of September 30, 2013 and December 31, 2012, 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 were fully triggered as of September 30, 2013 and December 31, 2012, the Company could request $78.6 million and $32.1 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, 2013 and December 31, 2012 is $78.6 million and $32.1 million, respectively. In addition, at September 30, 2013, the Company could have called on letters of credit in the amount of $9 million related to $10 million in commodity derivatives that are in a net asset position, compared to letters of credit of $10 million related to derivatives of $13 million at December 31, 2012, 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 Not Offset in the Statement of Financial Position
Millions of dollars	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Financial Instruments			Cash Collateral Received	Net Amount
As of September 30, 2013
Interest rate	$	124	—	$	124	$	(3	)	—	$	121
Commodity	1		—	1		—			—	1
Energy Management	10		—	10		—			—	10
Total	$	135	—	$	135	$	(3	)	—	$	132
Balance sheet location	Prepayments and other			$	89
	Other deferred debits and other assets			46
	Total			$	135

As of December 31, 2012
Interest rate	$	73	—			$	73	$	(17	)	—	$	56
Commodity	2		—			2		—			—	2
Energy Management	13		$	(1	)	12		—			—	12
Total	$	88	$	(1	)	$	87	$	(17	)	—	$	70
Balance sheet location	Prepayments and other					$	50
	Other deferred debits and other assets					37
	Total					$	87

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

						Gross Amounts Not Offset in the Statement of Financial Position
Millions of dollars	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Financial Instruments			Cash Collateral Posted			Net Amount
As of September 30, 2013
Interest rate	$	24	—	$	24	$	(3	)	$	(21	)	—
Commodity	3		—	3		—			(1		)	$	2
Energy Management	10		—	10		—			(8		)	2
	$	37	—	$	37	$	(3	)	$	(30	)	$	4
Balance sheet location	Prepayments and other			$	1
	Other current liabilities			12
	Other deferred credits and other liabilities			24
	Total			$	37

As of December 31, 2012
Interest rate	$	106	—			$	106	$	(17	)	$	(67	)	$	22
Commodity	4		—			4		—			—			4
Energy Management	13		$	(1	)	12		—			(11		)	1
	$	123	$	(1	)	$	122	$	(17	)	$	(78	)	$	27
Balance sheet location	Other current liabilities					$	80
	Other deferred credits and other liabilities					42
	Total					$	122

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 the 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 the Audit Committee’s 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 lock or forward starting swap agreements that are designated as cash flow hedges.  Except as described in the following paragraph, the effective portions of changes in fair value and payments made or received upon termination of such agreements are recorded in regulatory assets or regulatory liabilities.  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 authorization granted in October 2013, certain interest rate derivatives entered into by SCE&G will no longer be designated as cash flow hedges, and fair value changes and settlement amounts are to be recorded in its regulatory asset and liability accounts. Upon settlement, losses on swaps will be amortized over the lives of related debt issuances, and gains may be applied to undercollected fuel amounts or may be amortized to interest expense as 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

Consolidated SCE&G was a party to interest rate swaps designated as cash flow hedges with an aggregate notional amount of $571.4 million at September 30, 2013 and $971.4 million at December 31, 2012.

The fair value of interest rate derivatives was reflected in the condensed consolidated balance sheet as follows:

	Fair Values of Derivative Instruments
	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
Millions of dollars	Location	Value		Location	Value
As of September 30, 2013
Derivatives designated as hedging instruments
Interest rate	Prepayments and other	$	83	Other current liabilities	$	2
	Other deferred debits and other assets	41		Other deferred credits and other liabilities	1
Total		$	124		$	3
As of December 31, 2012
Derivatives designated as hedging instruments
Interest rate	Prepayments and other	$	42	Other current liabilities	$	66
	Other deferred debits and other assets	31		Other deferred credits and other liabilities	9
Total		$	73		$	75

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

Derivatives in Cash Flow Hedging Relationships	Gain Deferred in Regulatory Accounts					Loss Reclassified from Deferred Accounts into Income
	(Effective Portion)					(Effective Portion)
Millions of dollars	2013		2012		Location	2013			2012
Three Months Ended September 30,
Interest rate	$	19	$	23	Interest expense	$	(1	)	$	(1	)
Nine Months Ended September 30,
Interest rate	$	115	$	51	Interest expense	$	(2	)	$	(2	)

Derivatives not designated as Hedging Instruments		Loss Recognized in Income
Millions of dollars	Location	2013	2012
Three Months Ended September 30,
Commodity	Gas purchased for resale	—	—
Nine Months Ended September 30,
Commodity	Gas purchased for resale	—	$	(1	)

Hedge Ineffectiveness

Other gains (losses) recognized in income representing ineffectiveness on interest rate hedges designated as cash flow hedges were insignificant in each of the three and nine months ended September 30, 2013 and 2012, respectively.

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 on an ongoing basis. 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, 2013 and December 31, 2012, Consolidated SCE&G has posted $3.3 million and $35.2 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 Prepayments and other on the consolidated balance sheets. Collateral related to noncurrent positions is recorded in Other within Deferred Debits and Other Assets on the consolidated balance sheets. If all of the contingent features underlying these instruments had been fully triggered as of September 30, 2013 and December 31, 2012, Consolidated SCE&G could have been required to post an additional $- million and $22.7 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, 2013 and December 31, 2012 is $2.6 million and $57.9 million, respectively.

In addition, as of September 30, 2013 and December 31, 2012, 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 were fully triggered as of September 30, 2013 and December 31, 2012, Consolidated SCE&G could request $78.6 million and $32.1 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, 2013 and December 31, 2012 is $78.6 million and $32.1 million, respectively.

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

						Gross Amounts Not Offset in the Statement of Financial Position
Millions of dollars	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Financial Instruments			Cash Collateral Received	Net Amount
As of September 30, 2013
Interest rate	$	124	—	$	124	$	(3	)	—	$	121
Balance Sheet Location	Prepayments and other			$	83
	Other deferred debits and other assets			41
	Total			$	124

As of December 31, 2012
Interest rate	$	73	—	$	73	$	(17	)	—	$	56
Balance Sheet Location	Prepayments and other			$	42
	Other deferred debits and other assets			31
	Total			$	73

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

						Gross Amounts Not Offset in the Statement of Financial Position
Millions of dollars	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Statement of Financial Position	Net Amounts Presented in the Statement of Financial Position		Financial Instruments			Cash Collateral Posted		Net Amount
As of September 30, 2013
Interest rate	$	3	—	$	3	$	(3	)	$	—	$	—
Balance Sheet Location	Other current liabilities			$	2
	Other deferred credits and other liabilities			1
	Total			$	3

As of December 31, 2012
Interest rate	$	75	—	$	75	$	(17	)	$	(35	)	$	23
Balance Sheet Location	Other current liabilities			$	66
	Other deferred credits and other liabilities			9
	Total			$	75

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

9 Months Ended

Sep. 30, 2013

Accounting Policies [Abstract]

Reconciliation of the weighted average number of common shares

Reconciliations of the weighted average number of common shares for basic and diluted earnings per share computation purposes are as follows:     

	Third Quarter		Year to Date
Millions	2013	2012	2013	2012
Weighted Average Shares Outstanding - Basic	140.1	131.4	138.0	130.8
Effect of dilutive equity forward shares	—	2.4	0.6	2.3
Weighted Average Shares - Diluted	140.1	133.8	138.6	133.1

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AFFILIATED TRANSACTIONS - SCEG

9 Months Ended

Sep. 30, 2013

AFFILIATED TRANSACTIONS

AFFILIATED TRANSACTIONS

CGT transports natural gas to SCE&G to serve SCE&G’s retail gas customers and certain electric generation requirements.  Transportation services totaled approximately $25.3 million and $27.1 million for the nine months ended September 30, 2013 and 2012, respectively.  SCE&G had approximately $3.0 million and $3.4 million payable to CGT for transportation services at September 30, 2013 and December 31, 2012, respectively.

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 $132.7 million and $84.0 million for the nine months ended September 30, 2013 and 2012, respectively.  SCE&G’s payables to SEMI for such purposes were $13.2 million and $13.1 million as of September 30, 2013 and December 31, 2012, respectively.

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 owned 10% of Cope Refined Coal, LLC through December 31, 2012. SCE&G accounts for these investments using the equity method.  SCE&G’s receivables from these affiliates were $19.7 million at September 30, 2013 and $1.8 million at December 31, 2012.  SCE&G’s payables to these affiliates were $19.8 million at September 30, 2013 and $1.8 million at December 31, 2012.  SCE&G’s total purchases from these affiliates were $73.7 million and $87.3 million for the nine months ended September 30, 2013 and 2012, respectively.  SCE&G’s total sales to these affiliates were $73.4 million and $86.9 million for the nine months ended September 30, 2013 and 2012, respectively.

Consolidated SCE&G receives the following services from SCANA Services and its parent company, which are rendered at direct or allocated cost: information systems 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. Consolidated SCE&G’s payables for such purposes were $40.3 million and $45.8 million as of September 30, 2013 and December 31, 2012, respectively.

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

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Document and Entity Information Document	9 Months Ended
	Sep. 30, 2013	Oct. 31, 2013
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, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		140,548,894
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, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		40,296,147

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

9 Months Ended

Sep. 30, 2013

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.

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 47% and 44% of PSNC Energy’s natural gas inventory at September 30, 2013

and December 31, 2012, respectively, with a carrying value of $23.2 million and $19.6 million, respectively, through either capacity release or agency relationships.  Under the terms of the asset management agreements, PSNC Energy receives storage asset management fees. The agreements expire March 31, 2015.

Earnings Per Share

Earnings Per Share

The Company computes basic earnings per share by dividing net income by the weighted average number of common shares outstanding for the period.  The Company computes diluted earnings per share using this same formula after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method.  The Company has issued no securities that would have an antidilutive effect on earnings per share.

SCEG

Significant Accounting Policies

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

Variable Interest Entities

SCE&G has determined that it is the primary beneficiary of 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 $478 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.

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.