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, 2012

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	57-0784499
	(a South Carolina corporation)
	100 SCANA Parkway, Cayce, South Carolina 29033
	(803) 217-9000
1-3375	South Carolina Electric & Gas Company	57-0248695
	(a South Carolina corporation)
	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, 2012
SCANA Corporation	Without Par Value	131,792,649
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).

SEPTEMBER 30, 2012

			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	30
	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	55
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	59
	Item 4.	Controls and Procedures	60
PART II. OTHER INFORMATION			61
	Item 6.	Exhibits	61
Signatures			62
Exhibit Index			63

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, 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 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, including drought, 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

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
ARO	Asset Retirement Obligation
BLRA	Base Load Review Act
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury 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 and Stone and Webster, Inc., a subsidiary of The Shaw Group, Inc.
CSAPR	Cross-State Air Pollution Rule
CUT	Customer Usage Tracker
DHEC	South Carolina Department of Health and Environmental Control
DSM or DSM Programs	Demand reduction and energy efficiency programs
DT	Dekatherms (one million BTUs)
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
FERC	United States Federal Energy Regulatory Commission
Fuel Company	South Carolina Fuel Company, Inc.
GENCO	South Carolina Generating Company, Inc.
GHG	Greenhouse Gas
GWh	Gigawatt hour
IRP	Integrated Resource Plan
LOC	Lines of credit
MGP	Manufactured Gas Plant
MW	Megawatt
NASDAQ	The NASDAQ Stock Market, Inc.
NEIL	Nuclear Electric Insurance Limited
NCUC	North Carolina Utilities Commission
New Units	Nuclear Units 2 and 3 under construction at Summer Station
NRC	United States Nuclear Regulatory Commission
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

4

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
Westinghouse	Westinghouse Electric Company LLC

5

SCANA CORPORATION

FINANCIAL SECTION

6

PART I.  FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

SCANA CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited) 

Millions of dollars	September 30, 2012			December 31, 2011
Assets
Utility Plant In Service	$	11,631		$	12,000
Accumulated Depreciation and Amortization	(3,790		)	(3,836		)
Construction Work in Progress	1,945			1,482
Plant to be Retired, Net	418			—
Nuclear Fuel, Net of Accumulated Amortization	163			171
Goodwill, net of writedown of $230	230			230
Utility Plant, Net	10,597			10,047
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation of $141 and $131	307			305
Assets held in trust, net-nuclear decommissioning	94			84
Other investments	87			87
Nonutility Property and Investments, Net	488			476
Current Assets:
Cash and cash equivalents	41			29
Receivables, net of allowance for uncollectible accounts of $5 and $6	694			756
Inventories (at average cost):
Fuel and gas supply	304			313
Materials and supplies	134			129
Emission allowances	2			2
Prepayments and other	177			236
Deferred income taxes	9			26
Total Current Assets	1,361			1,491
Deferred Debits and Other Assets:
Regulatory assets	1,290			1,279
Other	228			241
Total Deferred Debits and Other Assets	1,518			1,520
Total	$	13,964		$	13,534

7

Millions of dollars	September 30, 2012		December 31, 2011
Capitalization and Liabilities
Common Equity	$	4,095	$	3,889
Long-Term Debt, net	4,976		4,622
Total Capitalization	9,071		8,511
Current Liabilities:
Short-term borrowings	394		653
Current portion of long-term debt	176		31
Accounts payable	297		374
Customer deposits and customer prepayments	103		103
Taxes accrued	133		154
Interest accrued	78		74
Dividends declared	65		63
Derivative financial instruments	81		77
Other	84		113
Total Current Liabilities	1,411		1,642
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,598		1,533
Deferred investment tax credits	37		40
Asset retirement obligations	500		474
Postretirement benefits	299		291
Regulatory liabilities	863		778
Other	185		265
Total Deferred Credits and Other Liabilities	3,482		3,381
Commitments and Contingencies (Note 9)	—		—
Total	$	13,964	$	13,534

See Notes to Condensed Consolidated Financial Statements.

8

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
Millions of dollars, except per share amounts	2012			2011			2012			2011
Operating Revenues:
Electric	$	714		$	728		$	1,851		$	1,903
Gas - regulated	109			115			513			613
Gas - nonregulated	215			249			690			858
Total Operating Revenues	1,038			1,092			3,054			3,374
Operating Expenses:
Fuel used in electric generation	239			277			617			739
Purchased power	9			6			20			16
Gas purchased for resale	248			291			837			1,101
Other operation and maintenance	165			166			510			501
Depreciation and amortization	89			87			267			259
Other taxes	50			50			156			153
Total Operating Expenses	800			877			2,407			2,769
Operating Income	238			215			647			605
Other Income (Expense):
Other income	13			12			39			36
Other expenses	(9		)	(10		)	(29		)	(29		)
Interest charges, net of allowance for borrowed funds used during construction of $3, $2, $8 and $7	(75		)	(73		)	(219		)	(212		)
Allowance for equity funds used during construction	6			5			13			13
Total Other Expense	(65		)	(66		)	(196		)	(192		)
Income Before Income Tax Expense	173			149			451			413
Income Tax Expense	51			44			136			124
Net Income	$	122		$	105		$	315		$	289
Per Common Share Data
Basic Earnings Per Share of Common Stock	$	.93		$	0.81		$	2.41		$	2.25
Diluted Earnings Per Share of Common Stock	$	.91		$	0.81		$	2.37		$	2.23
Weighted Average Common Shares Outstanding (millions)
Basic	131.4			129.1			130.8			128.5
Diluted	133.8			130.3			133.1			129.8
Dividends Declared Per Share of Common Stock	$	.495		$	.485		$	1.485		$	1.455

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	2012		2011			2012			2011
Net Income	$	122	$	105		$	315		$	289
Other Comprehensive Income (Loss), net of tax:
Unrealized gains (losses) on cash flow hedging activities arising during period, net of tax benefit of $-, $21, $4 and $29	1		(33		)	(6		)	(46		)
Losses on cash flow hedging activities reclassified to net income, net of tax benefit of $2, $1, $11 and $5	3		2			17			8
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax of $ -, $ -, $- and $-	—		—			1			—
Other Comprehensive Income (Loss)	4		(31		)	12			(38		)
Total Comprehensive Income (1)	$	126	$	74		$	327		$	251

(1)  Accumulated other comprehensive loss totaled $81.8 million as of September 30, 2012 and $93.8 million as of December 31, 2011.

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	2012			2011
Cash Flows From Operating Activities:
Net income	$	315		$	289
Adjustments to reconcile net income to net cash provided from operating activities:
(Earnings) losses from equity method investments, net of distributions	(1		)	1
Deferred income taxes, net	74			97
Depreciation and amortization	277			263
Amortization of nuclear fuel	38			27
Allowance for equity funds used during construction	(13		)	(13		)
Cash provided (used) by changes in certain assets and liabilities:
Receivables	46			175
Inventories	(34		)	2
Prepayments and other	58			68
Regulatory liabilities	47			(12		)
Accounts payable	(7		)	(108		)
Taxes accrued	(21		)	(21		)
Interest accrued	4			(1		)
Regulatory assets	(2		)	(88		)
Changes in other assets	5			(10		)
Changes in other liabilities	(18		)	8
Net Cash Provided From Operating Activities	768			677
Cash Flows From Investing Activities:
Property additions and construction expenditures	(868		)	(715		)
Proceeds from investments (including derivative collateral posted)	364			16
Purchase of investments (including derivative collateral posted)	(326		)	(116		)
Proceeds from interest rate contract settlement	14			—
Payments upon interest rate contract settlement	(51		)	(61		)
Net Cash Used For Investing Activities	(867		)	(876		)
Cash Flows From Financing Activities:
Proceeds from issuance of common stock	73			73
Proceeds from issuance of long-term debt	763			796
Repayment of long-term debt	(274		)	(627		)
Dividends	(192		)	(185		)
Short-term borrowings, net	(259		)	161
Net Cash Provided From Financing Activities	111			218
Net Increase In Cash and Cash Equivalents	12			19
Cash and Cash Equivalents, January 1	29			55
Cash and Cash Equivalents, September 30	$	41		$	74
Supplemental Cash Flow Information:
Cash paid for– Interest (net of capitalized interest of $8 and $7)	$	212		$	206
– Income taxes	67			—
Noncash Investing and Financing Activities:
Accrued construction expenditures	79			62
Capital leases	4			2

 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, 2012 and 2011

(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, 2011. 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.

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 dilutive purposes are as follows:

	Quarterly		Year to Date
In Millions	2012	2011	2012	2011
Weighted Average Shares Outstanding - Basic	131.4	129.1	130.8	128.5
Net effect of dilutive equity forward shares	2.4	1.2	2.3	1.3
Weighted Average Shares - Diluted	133.8	130.3	133.1	129.8

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 48%  and 45% of PSNC Energy’s natural gas inventory at September 30, 2012 and December 31, 2011, respectively, with a carrying value of $20.4 million and $28.7 million, respectively, through either capacity release or agency relationships.  Under the terms of the asset management agreements, PSNC Energy receives storage asset management fees.  No fees are received under supply service agreements.  The agreements expire at various times through March 31, 2013.

New Accounting Matters

Effective for the first quarter of 2012, the Company adopted accounting guidance that revises how comprehensive income is presented in its financial statements.  The adoption of this guidance has not impacted, and is not expected to impact, the Company's results of operations, cash flows or financial position.

Effective for the first quarter of 2012, the Company adopted accounting guidance that permits it to make a qualitative assessment about the likelihood of goodwill impairment each year.  Such an assessment was performed with respect to certain goodwill, and that assessment led the Company to determine that performing a two-step quantitative impairment test was unnecessary.  For other goodwill, the two-step quantitative test was performed. The adoption of this guidance has not impacted, and is not expected to impact, the Company's results of operations, cash flows or financial position.

12

Effective for the first quarter of 2012, the Company adopted accounting guidance that amended existing requirements for measuring fair value and for disclosing information about fair value measurements.  The adoption of this guidance has not impacted, and is not expected to impact, the Company's results of operations, cash flows or financial position.

2. RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric

SCE&G's retail electric rates are established in part by using 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 February 2012, SCE&G requested authorization to decrease the total fuel cost component of its retail electric rates to be effective the first billing cycle of May 2012. In March 2012, SCE&G, the ORS and SCEUC entered into a settlement agreement in which SCE&G agreed to recover an amount equal to its actual under-collected balance of base fuel and variable environmental costs as of April 30, 2012 in the next rate period beginning with the first billing cycle of May 2012. In April 2012, the SCPSC approved the settlement agreement and ruled among other matters that SCE&G's fuel purchasing practices and policies were reasonable and prudent for the period January 1, 2011, through December 31, 201l.

On June 29, 2012, SCE&G filed an application with the SCPSC requesting an increase in retail revenues of approximately $151.5 million or 6.61%.  SCE&G also requested a mid-period reduction to the cost of fuel component in rates, as well as a reduction in the DSM component rider to retail rates. These adjustments will reduce the overall revenue increase requested to 3.75%. In addition, SCE&G requested recovery of and a return on the net carrying value of certain generating plant assets described below. SCE&G has requested that the proposed increase be effective January 1, 2013. A public hearing on this matter has been scheduled to begin on November 26, 2012; a decision from the SCPSC is expected in late December 2012.

On May 30, 2012, SCE&G filed its annual 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 plans to retire by 2018, subject to future developments in environmental regulations, among other matters. These units have an aggregate generating capacity (summer 2012) of 730 MW. The net carrying value of these units totaled $418 million at September 30, 2012, and is identified as Plant to be Retired, Net in the condensed consolidated financial statements. Included in this amount is approximately $23 million related to a unit that SCE&G plans to retire by the end of 2012. In its June 29, 2012 application with the SCPSC, described above, SCE&G has requested recovery of and a return on the net carrying value of this unit. SCE&G plans to make similar requests for the remaining units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. SCE&G continues to depreciate these units using composite straight-line rates approved by the SCPSC while the assets are in use.

In July 2010, the SCPSC issued an order approving a 4.88% overall increase in SCE&G’s retail electric base rates and authorized an allowed return on common equity of 10.7%. The SCPSC’s order adopted various stipulations among SCE&G, the ORS and other intervening parties. Among other matters, the SCPSC’s order provided for a $48.7 million credit to SCE&G’s customers over two years to be offset by accelerated recognition of previously deferred state income tax credits.

The SCPSC has approved DSM Programs for SCE&G's customers, including the establishment of an annual rider, approved by the SCPSC, to allow recovery of the costs and lost net margin revenue associated with the DSM Programs, along with an incentive for investing in such programs. SCE&G must submit annual filings to the SCPSC regarding the DSM Programs, net lost revenues, program costs, incentives and net program benefits.  In January 2011, SCE&G submitted to the SCPSC an annual update on DSM Programs and rate rider. In May 2011, the SCPSC approved the updated rate rider, which became effective the first billing cycle of June 2011. In January 2012, SCE&G submitted to the SCPSC another annual update on DSM Programs and rate rider. In April 2012, the SCPSC approved the updated rate rider and authorized SCE&G to increase its rates to recover approximately $19.6 million related to DSM Programs as set forth in its petition. The increase became effective the first billing cycle of May 2012.

13

Electric – BLRA

The SCPSC has approved SCE&G's combined application pursuant to the BLRA seeking a certificate of environmental compatibility and public convenience and necessity and for a base load review order relating to the proposed construction and operation by SCE&G and Santee Cooper of the New Units at Summer Station.  Under the BLRA, the SCPSC conducted a full pre-construction prudency review of the proposed units and the engineering, procurement, and construction contract under which they are being built.  The SCPSC prudency finding is binding on all future related rate proceedings so long as the construction proceeds in accordance with schedules, estimates and projections, as approved by the SCPSC.

    In May 2011, the SCPSC approved an updated capital cost schedule sought by SCE&G that, among other matters, incorporated then-identifiable capital costs of $173.9 million (SCE&G's portion in 2007 dollars). On May 15, 2012, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost and construction schedule for the New Units.  This petition replaced a February 29, 2012 petition, which was withdrawn.  The updated capital cost schedule in this petition reflects an increase of $283 million (SCE&G's portion in 2007 dollars) over the cost approved in the May 2011 order.  This petition includes additional identifiable capital costs of approximately $6 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, this petition includes 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 (which claims are discussed in Note 9).  The SCPSC approved the updated construction schedule and substantially all of the capital costs in this petition on November 7, 2012.

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 following years:

Year	Increase	Amount (Millions)
2012	2.3%	$52.1
2011	2.4%	$52.8

Gas

SCE&G

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

Year	Action			Amount (Millions)
2012	2.1	%	Increase	$7.5
2011	2.1	%	Increase	$8.6

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 annual PGA hearing to review SCE&G's gas purchasing policies and procedures was held in November 2011 before the SCPSC. The SCPSC issued an order in January 2012 finding that SCE&G's gas purchasing policies and practices during the review period of August 1, 2010 through July 31, 2011, were reasonable and prudent and authorized the suspension of SCE&G's natural gas hedging program. The next annual PGA hearing is scheduled for November 8, 2012.

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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 March 2012, the NCUC approved a five cent per therm decrease in the cost of gas component of PSNC Energy's rates. The rate adjustment was effective with the first billing cycle in April 2012. In addition, in January 2012, the NCUC approved a five cent per therm decrease in the cost of gas component of PSNC Energy's rates. This rate adjustment was effective with the first billing cycle in February 2012.

In October 2012, in connection with PSNC Energy's 2012 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, 2012.

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 liabilities which are summarized in the following tables.  Substantially all of our 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, 2012		December 31, 2011
Regulatory Assets:
Accumulated deferred income taxes	$	244	$	243
Under-collections - electric fuel adjustment clause	—		28
Environmental remediation costs	44		30
AROs and related funding	321		316
Franchise agreements	37		40
Deferred employee benefit plan costs	390		392
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	159		154
Deferred pollution control costs	35		25
Other	60		45
Total Regulatory Assets	$	1,290	$	1,279

Regulatory Liabilities:
Accumulated deferred income taxes	$	21	$	23
Asset removal costs	688		662
Storm damage reserve	27		32
Monetization of bankruptcy claim	32		34
Deferred gains on interest rate derivatives	85		26
Planned major maintenance	8		—
Other	2		1
Total Regulatory Liabilities	$	863	$	778

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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 expected to be recovered in retail electric rates over periods exceeding 12 months. 

Environmental remediation costs represent costs associated with the assessment and clean-up of MGP sites currently or formerly owned by the Company.  These regulatory assets are expected to be recovered over periods of up to approximately 28 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 95 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 amountsof 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.  A significant majority of these deferred costs are expected to be recovered through utility rates over average service periods of participating employees, or up to approximately 12 years.

Planned major maintenance related to certain fossil hydro 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 hydro turbine/generation equipment maintenance.  Nuclear refueling charges are accrued during each 18-month refueling outage cycle as a component of cost of service.

Deferred losses or gains on interest rate derivatives represent the effective portions of changes in fair value and payments made or received upon termination of certain interest rate derivatives designated as cash flow hedges.  These amounts are expected to be amortized to interest expense over the lives of the underlying debt, up to approximately 30 years.

Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the installation of scrubbers at Wateree and Williams Stations pursuant to specific regulatory orders.  Such costs related to Williams Station amount to $9.1 million at September 30, 2012 and are being recovered through utility rates over approximately 30 years.  The remaining costs relate to Wateree Station and SCE&G is allowed to accrue interest on these deferred costs until such costs are approved for recovery by the SCPSC.

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, certain transmission and distribution insurance premiums and certain tree trimming and vegetation management expenditures in excess of amounts included in base rates.  During the nine months ended September 30, 2012 and 2011, SCE&G applied costs of $4.6 million and $3.6 million, respectively, to the reserve.  Pursuant to the SCPSC’s July 2010 retail electric rate order approving an electric rate increase, SCE&G suspended storm damage reserve collection through rates indefinitely.

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

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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 or by 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, 2012 and 2011 were as follows:

Millions of dollars	2012			2011
Balance at January 1,	$	3,889		$	3,702
Common stock issued	73			73
Dividends declared	(194		)	(188		)
Comprehensive income	327			251
Balance as of September 30,	$	4,095		$	3,838

Authorized shares of common stock were 200 million as of September 30, 2012 and December 31, 2011.  Outstanding shares of common stock were 131.5 million and 129.9 million at September 30, 2012 and December 31, 2011, respectively.

In May 2010 SCANA entered into forward sales contracts for approximately 6.6 million common shares which, after being extended by amendments, SCANA expects to settle in the first quarter of 2013. There have been no shares issued under the forward sales contracts.

4. LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

     In July 2012, SCE&G issued $250 million of 4.35% first mortgage bonds due February 1, 2042, which constituted a reopening of $250 million of its 4.35% first mortgage bonds issued in January 2012. Proceeds from these sales were used to repay short-term debt primarily incurred as a result of SCE&G's construction program, to finance capital expenditures and for general corporate purposes.

In January 2012, SCANA issued $250 million of 4.125% medium term notes due February 1, 2022. Proceeds from the sale were used to retire SCANA's $250 million6.25% medium term notes due February 1, 2012.

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: 

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	SCANA						SCE&G						PSNC Energy
Millions of dollars	September 30, 2012			December 31, 2011			September 30, 2012			December 31, 2011			September 30, 2012		December 31, 2011
Lines of credit:
Committed long-term
Total	$	300		$	300		$	1,100		$	1,100		$	100	$	100
LOC advances	—			—			—			—			—		—
Weighted average interest rate	—			—			—			—			—		—
Outstanding commercial paper (270 or fewer days)	$	66		$	131		$	327		$	512		—		$	10
Weighted average interest rate	0.80		%	0.63		%	0.47		%	0.56		%	—		0.57		%
Letters of credit supported by LOC	$	3		$	3		$	0.3		$	0.3		—		—
Available	$	231		$	166		$	773		$	588		$	100	$	90

At September 30, 2012, SCANA, SCE&G (including Fuel Company) and PSNC Energy were parties to credit agreements in the amounts of $300 million, $1,100 million, of which $400 million related to Fuel Company, and $100 million, respectively. These credit agreements were 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, fossil fuel, and emission and other environmental allowances.  As of September 30, 2012, Wells Fargo Bank, National Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provided 10.0% of the aggregate $1.5 billion credit facilities, Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A. and UBS Loan Finance LLC each provided 8.0%, and Deutsche Bank AG New York Branch, Union Bank, N.A. and U.S. Bank National Association each provided 5.3%.  Three other banks provided the remaining 6.0%.

These credit agreements were amended and extended in October 2012 to expire in October 2017. In connection with the amendment and extension of the agreements, the amount of Fuel Company's credit agreement was increased to $500 million, and the other companies' credit agreements remained the same size. In addition, SCE&G entered into a new three-year credit agreement in the amount of $200 million, which is scheduled to expire in October 2015. The amended and extended credit agreements, together with SCE&G's new three-year credit agreement total an aggregate of $1.8 billion. Wells Fargo Bank, National Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provide 10.7% of the aggregate 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.

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.

5. INCOME TAXES

In connection with a change in method of tax accounting for certain repair costs, the Company had previously recorded approximately $38 million of unrecognized tax benefit. During the first quarter of 2012, newadministrative guidance from the Internal Revenue Service was published. Under this guidance, the Company has recognized the entire $38 million of unrecognized tax benefit. Since this change was primarily a temporary difference, the recognition of this benefit did not have a significant effect on the Company's effective tax rate. No other material changes in the status of the Company's tax positions have occurred through September 30, 2012.

The Company recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses. In connection with the recognition of tax benefits described above, during the quarter ended March 31, 2012, the Company reversed $2 million of interest expense which had been accrued during 2011. 

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.  The fair value of

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derivative instruments is determined by reference to quoted market prices of listed contracts, published quotations or, for interest rate swaps, discounted cash flow models with independently sourced data.

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 Board of Directors with regard to the management of risk and brings to the Board’s attention any 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 and financial institutions.  Cash settlements of commodity derivatives are classified as an operating activity in the condensed consolidated statements of cash flows.

The SCPSC authorized the suspension of SCE&G's natural gas hedging program in January 2012. The fair value of such derivative instruments remaining to be settled were not significant for any period presented.

PSNC Energy hedges natural gas purchasing activities using over-the-counter options and swaps and NYMEX futures and options.  PSNC Energy’s tariffs also include a provision for the recovery of actual gas costs incurred.  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 over- or under-recovery of gas costs.  These derivative financial instruments are not designated as hedges for accounting purposes.

The unrealized gains and losses on qualifying cash flow hedges of nonregulated operations are deferred in OCI.  When the hedged transactions affect earnings, the previously recorded gains and losses are reclassified from OCI 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 the fair value attributable to changes in interest rates on certain debt issuances.  These swaps may be designated as either fair value hedges or cash flow hedges.

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.  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, and for the holding company or nonregulated subsidiaries, are recorded in OCI.  Such amounts are amortized to interest expense over the term of the underlying debt and are classified as an operating activity for cash flow purposes. Ineffective portions are recognized in income.  Cash payments made or received upon termination of these financial instruments are classified as an investing activity for cash flow purposes.

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Quantitative Disclosures Related to Derivatives

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

	Commodity and Other Energy Management Contracts (in DT)
Hedge designation	Gas Distribution	Retail Gas Marketing	Energy Marketing	Total
As of September 30, 2012
Cash flow	—	9,650,000	20,455,750	30,105,750
Not designated (a)	8,580,000	—	22,330,074	30,910,074
Total (a)	8,580,000	9,650,000	42,785,824	61,015,824
As of December 31, 2011
Cash flow	—	6,566,000	29,861,763	36,427,763
Not designated (b)	9,080,000	—	31,943,563	41,023,563
Total (b)	9,080,000	6,566,000	61,805,326	77,451,326

(a)  Includes an aggregate 5,910,000 DT related to basis swap contracts in Energy Marketing.

(b)  Includes an aggregate 9,626,000 DT related to basis swap contracts in Energy Marketing.

The Company was not party to any interest rate swaps designated as fair value hedges at September 30, 2012. The Company was party to interest rate swaps designated as fair value hedges with aggregate notional amounts of $253.2 million at December 31, 2011, and was party to interest rate swaps designated as cash flow hedges with aggregate notional amounts of $1.1 billion at September 30, 2012 and $822.6 million at December 31, 2011.

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 (c)	Value		Location (c)	Value
As of September 30, 2012
Derivatives designated as hedging instruments
Interest rate contracts	Prepayments and other	$	27	Other current liabilities	$	75
	Other deferred debits and other assets	20		Other deferred credits and other liabilities	42
Commodity contracts	Prepayments and other	2		Other current liabilities	3
	Other current liabilities	2
Total		$	51		$	120
Derivatives not designated as hedging instruments
Commodity contracts	Prepayments and other	$	2
Energy management contracts	Prepayments and other	8		Prepayments and other	$	1
	Other deferred debits and other assets	7		Other current liabilities	7
				Other deferred credits and other liabilities	7
Total		$	17		$	15

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As of December 31, 2011
Derivatives designated as hedging instruments
Interest rate contracts	Prepayments and other	$	2	Other current liabilities	$	55
				Other deferred credits and other liabilities	103
Commodity contracts	Other current liabilities	1		Prepayments and other	1
				Other current liabilities	10
				Other deferred credits and other liabilities	3
Total		$	3		$	172
Derivatives not designated as hedging instruments
Energy management contracts	Prepayments and other	$	17	Prepayments and other	$	3
	Other deferred debits and other assets	10		Other current liabilities	13
				Other deferred credits and other liabilities	9
Total		$	27		$	25

(c) Asset derivatives represent unrealized gains to the Company, and liability derivatives represent unrealized losses.  In the Company’s condensed consolidated balance sheets, unrealized gain and loss positions on commodity contracts with the same counterparty are reported as either a net asset or liability, and for purposes of the above disclosure they are reported on a gross basis.

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

With regard to the Company's interest rate swaps designated as fair value hedges, the gains on those swaps and the losses on the hedged fixed rate debt are recognized in current earnings and included in interest expense. These gains and losses, combined with the amortization of deferred gains on previously terminated swaps, resulted in increases to interest expense that were insignificant for each of the three and nine months ended September 30, 2012 and were $0.9 million and $4.9 million for the three and nine months ended September 30, 2011, respectively.

Derivatives in Cash Flow Hedging Relationships

						Gain (Loss) Reclassified from
Derivatives in Cash Flow	Gain (Loss) Deferred					Deferred Accounts into Income
Hedging Relationships	in Regulatory Accounts					(Effective Portion)
Millions of dollars	(Effective Portion)					Location	Amount
	2012		2011				2012			2011
Three Months Ended September 30,
Interest rate contracts	$	23	$	(63	)	Interest expense	$	(1	)	$	(1	)
Nine Months Ended September 30,
Interest rate contracts	$	51	$	(72	)	Interest expense	$	(2	)	$	(2	)

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	Gain (Loss)						Gain (Loss) Reclassified from
Derivatives in Cash Flow	Recognized in OCI,						Accumulated OCI into Income,
Hedging Relationships	net of tax						net of tax (Effective Portion)
Millions of dollars	(Effective Portion)						Location	Amount
	2012			2011				2012			2011
Three Months Ended September 30,
Interest rate contracts	$	(1	)	$	(28	)	Interest expense	$	(2	)	$	(1	)
Commodity contracts	2			(5		)	Gas purchased for resale	(1		)	(1		)
Total	$	1		$	(33	)		$	(3	)	$	(2	)
Nine Months Ended September 30,
Interest rate contracts	$	(5	)	$	(39	)	Interest expense	$	(5	)	$	(3	)
Commodity contracts	(1		)	(7		)	Gas purchased for resale	(12		)	(5		)
Total	$	(6	)	$	(46	)		$	(17	)	$	(8	)

As of September 30, 2012, the Company expects that during the next 12 months reclassifications from accumulated other comprehensive gain to earnings arising from cash flow hedges will include approximately $0.6 million as a decrease to gas cost and approximately $6.0 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels.  As of September 30, 2012, all of the Company’s commodity cash flow hedges settle by their terms before the end of 2015.

Derivatives not designated as Hedging Instruments	Gain (Loss) Recognized in Income
Millions of dollars	Location	2012			2011
Three Months Ended September 30,
Commodity contracts	Gas purchased for resale	$	—		$	—
Nine Months Ended September 30,
Commodity contracts	Gas purchased for resale	$	(1	)	$	(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, 2012 and were $0.8 million and $1.1 million for the three and nine months ended September 30, 2011, 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, surety bonds, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. the collateral agreements require a counterparty to post cash, surety bonds 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 require the Company to provide collateral upon the occurrence of specific events, primarily credit downgrades.  As of September 30, 2012 and December 31, 2011, the Company has posted $89.1 million and $140.3 million, respectively, of collateral related to derivatives with contingent provisions that are 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 the noncurrent positions is recorded in Other within Deferred Debits and Other Assets on the consolidated balance sheets. If all of the contingent

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features underlying these instruments were fully triggered as of September 30, 2012 and December 31, 2011, the Company would be required to post an additional $28.3 million and $50.7 million, respectively, of collateral to its counterparties.  The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of September 30, 2012 and December 31, 2011 is $117.4 million and $191.0 million, respectively.

In addition, as of September 30, 2012 and December 31, 2011, 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, 2012 and December 31, 2011, the Company could request $45.8 million and $1.1 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, 2012 and December 31, 2011 is $45.8 million and $1.1 million, respectively. In addition, at September 30, 2012, the Company may call on letters of credit in the amount of $10 million related to $12 million in commodity derivatives that are in a net asset position, compared to letters of credit of $12 million related to derivatives of $27 million at December 31, 2011.

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		Significant Other
		Markets for Identical Assets		Observable Inputs
Millions of dollars		(Level 1)		(Level 2)
As of September 30, 2012
Assets -	Available for sale securities	$	8	—
	Interest rate contracts	—		$	47
	Commodity contracts	3		3
	Energy management contracts	—		15
Liabilities -	Interest rate contracts	—		117
	Commodity contracts	—		3
	Energy management contracts	—		17
As of December 31, 2011
Assets -	Available for sale securities	$	3	—
	Interest rate contracts	—		$	2
	Commodity contracts	—		1
	Energy management contracts	—		27
Liabilities -	Interest rate contracts	—		158
	Commodity contracts	1		13
	Energy management contracts	—		26

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 and 2 during any period presented.

Financial instruments for which the carrying amount may not equal estimated fair value at September 30, 2012 and December 31, 2011 were as follows:

	September 30, 2012				December 31, 2011
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	5,153.0	$	6,241.6	$	4,653.0	$	5,479.2

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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.  Carrying values reflect the fair values of interest rate swaps designated as fair value hedges, based on discounted cash flow models with independently sourced market data.  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

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

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2012			2011			2012		2011
Three months ended September 30,
Service cost	$	5.0		$	4.5		$	1.1	$	1.0
Interest cost	10.9			10.4			2.9		3.2
Expected return on assets	(15.0		)	(15.3		)	—		—
Prior service cost amortization	1.8			1.7			0.2		0.2
Transition obligation amortization	—			—			0.2		0.1
Amortization of actuarial loss	4.5			3.1			—		0.1
Net periodic benefit cost	$	7.2		$	4.4		$	4.4	$	4.6
Nine months ended September 30,
Service cost	$	14.7		$	13.7		$	3.6	$	3.2
Interest cost	32.2			32.6			8.9		9.2
Expected return on assets	(44.6		)	(47.7		)	—		—
Prior service cost amortization	5.3			5.3			0.7		0.8
Transition obligation amortization	—			—			0.5		0.5
Amortization of actuarial loss	13.8			9.1			0.4		0.3
Net periodic benefit cost	$	21.4		$	13.0		$	14.1	$	14.0

No contribution to the pension trust will be necessary in or for 2012, nor will limitations on benefit payments apply.   As authorized by the SCPSC, SCE&G defers all pension expense related to retail electric and gas operations as a regulatory asset.  Costs totaling $4.0 million and $11.4 million were deferred for the three and nine months ended September 30, 2012, respectively. Costs totaling $2.2 million and $6.8 million were deferred for the corresponding periods in 2011. 

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 $12.6 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 $117.5 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $17.5 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 $78.3 million per incident, but not more than $11.7 million per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years.

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SCE&G currently maintains policies (for itself and on behalf of Santee Cooper) with NEIL.  The policies provide coverage to the nuclear facility for property damage and outage costs up to $2.75 billion. 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. 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 $37.3 million.

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

Environmental

SCE&G

On April 13, 2012, the EPA issued a proposed rule to establish a new source performance standard for GHG emissions from fossil fuel-fired electric generating units. If enacted, the proposed rule will limit emissions of carbon dioxide from new fossil fuel-fired electric utility generating units. The Company is evaluating the proposed rule, but cannot predict when the rule will become final, if at all, or what conditions it 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, including South Carolina, 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 would have replaced CAIR and the Clean Air Transport Rule proposed in July 2010 and was aimed at addressing power plant emissions that may contribute to air pollution in other states.  The rule would have required 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 U.S. Court of Appeals for the D.C. Circuit vacated CSAPR and left CAIR in place. On October 5, 2012, the EPA filed a petition for rehearing of the U. S. Court of Appeals order. Air quality control installations that SCE&G and GENCO have already completed 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 CAIR or other rules issued by the EPA are expected to be recoverable through rates.

In 2005, the EPA issued the CAMR which established a mercury emissions cap and trade program for coal-fired power plants. Numerous parties challenged the rule and, on February 8, 2008, the United States Circuit Court for the District of Columbia vacated the rule for electric utility steam generating units.  In March 2011, the EPA proposed new standards for mercury and other specified air pollutants. The rule containing the proposed new standards, which became effective on April 16, 2012, provides up to four years for facilities to meet the standards. The rule is currently being evaluated by the Company. 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 enactment of these environmental regulations, along with other factors, has resulted in the inclusion in SCE&G's most recently filed IRP of its plans to retire a total of six coal-fired units by 2018, subject to future developments in environmental regulations, among other matters.

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.  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.  SCE&G defers site assessment and cleanup costs and expects to recover them through rates. 

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SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals.  These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC and the EPA.  SCE&G anticipates that major remediation activities at all these sites will continue until 2015 and will cost an additional $22.4 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 and insurance settlements.  At September 30, 2012, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $38.6 million and are included in regulatory assets.

PSNC Energy

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 $3.1 million, the estimated remaining liability at September 30, 2012. PSNC Energy expects to recover through rates any cost, net of insurance recovery, allocable to PSNC Energy arising from the remediation of these sites.

Nuclear Generation

SCE&G and Santee Cooper are parties to construction and operating agreements in which they agreed to be joint owners, and share operating costs and generation output, of two1,117MW nuclear generation units currently being constructed at the site of Summer Station, with SCE&G responsible for 55% of the cost and receiving 55% of the output, and Santee Cooper responsible for and receiving the remaining 45%.  Under these agreements, SCE&G has the primary responsibility for oversight of the construction of the New Units and will be responsible for the operation of the New Units as they come online. 

SCE&G, on behalf of itself and as agent for Santee Cooper, entered into the EPC Contract with the Consortium for the design, procurement and construction of the New Units.  SCE&G's share of the estimated cash outlays (future value, excluding AFC) totals approximately $6 billion for plant costs and related transmission infrastructure costs, which costs are projected based on historical one-year and five-year escalation rates as required by the SCPSC.

On March 30, 2012, the NRC approved and issued COLs for the New Units.  On April 19, 2012, SCE&G, on behalf of itself and as agent for Santee Cooper, issued a Full Notice to Proceed to the Consortium for construction of the New Units, allowing for the commencement of safety related aspects of the project.  The first New Unit is scheduled for substantial completion in March 2017, and the second New Unit is scheduled for substantial completion in May 2018.

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 structural 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. On July 11, 2012, SCE&G and the Consortium finalized an agreement which set SCE&G's portion of the costs for these specific claims at approximately $138 million (in 2007 dollars).  SCE&G anticipates that these additional costs, as well as other costs that may be identified from time to time, will be recoverable through rates.

On May 15, 2012, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost and construction schedule for the New Units.  This petition replaced a February 29, 2012 petition, which was withdrawn.  The updated capital cost schedule in this petition reflects an increase of $283 million (SCE&G's portion in 2007 dollars) over the cost approved in a May 2011 order.  This petition includes additional identifiable capital costs of approximately $6 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, this petition includes revised substantial completion dates for the New Units based on the March 30, 2012 issuance of the COL and costs finalized in the July 11, 2012 agreement previously discussed. The SCPSC approved the updated construction schedule and substantially all of the capital costs in this petition on November 7, 2012.

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When the NRC issued the COLs for the New Units, it imposed two conditions on the COLs, with the first requiring inspection and testing of certain components of the New Units' passive cooling system, and the second 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 tsunami resulting from a massive earthquake, which severely damaged several nuclear generating units and their back-up cooling systems in Japan.  SCE&G is evaluating the

impact these conditions and requirements impose on the construction and operation of the New Units.  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.

As previously reported, SCE&G has been advised by Santee Cooper that it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation in the New Units.  Santee Cooper has entered into letters of intent with several parties that may result in one or more of them executing a power purchase agreement or acquiring a portion of Santee Cooper's ownership interest in the New Units.  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 commercial operation 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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	External			Intersegment			Operating			Net
Millions of dollars	Revenue			Revenue			Income			Income
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
Three Months Ended September 30, 2011
Electric Operations	$	728		$	2		$	225		n/a
Gas Distribution	114			1			(11		)	n/a
Retail Gas Marketing	68			—			n/a			$	(5	)
Energy Marketing	180			49			n/a			2
All Other	10			102			5			(6		)
Adjustments/Eliminations	(8		)	(154		)	(4		)	114
Consolidated Total	$	1,092		$	—		$	215		$	105

Nine months Ended September 30, 2011
Electric Operations	$	1,903		$	6		$	487	n/a
Gas Distribution	606			1			75		n/a
Retail Gas Marketing	348			—			n/a		$	14
Energy Marketing	510			146			n/a		4
All Other	30			308			13		(5		)
Adjustments/Eliminations	(23		)	(461		)	30		276
Consolidated Total	$	3,374		$	—		$	605	$	289

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	September 30,		December 31,
Segment Assets	2012		2011
Electric Operations	$	8,750	$	8,222
Gas Distribution	2,208		2,179
Retail Gas Marketing	121		185
Energy Marketing	91		114
All Other	1,276		1,377
Adjustments/Eliminations	1,518		1,457
Consolidated Total	$	13,964	$	13,534

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Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTSOF 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, 2011.

RESULTS OF OPERATIONS

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2012

AS COMPARED TO THE CORRESPONDING PERIODS IN 2011

Earnings Per Share

Earnings per share was as follows:

	Third Quarter		Year to Date
Millions of dollars	2012	2011	2012	2011
Basic earnings per share	$0.93	$0.81	$2.41	$2.25
Diluted earnings per share	$0.91	$0.81	$2.37	$2.23

Third Quarter

Basic earnings per share increased by $.11 due to higher electric margin, by $.02 due to higher gas margin, by $.01 due to lower operating expenses and by $.01 due to other items. These increases were partially offset by $.01 due to higher depreciation expense, by $.01 due to higher interest expense and by $.01 due to dilution from additional shares outstanding.

Year to Date

Basic earnings per share increased by $.36 due to higher electric margin and by $.01 due to other items. This increase was partially offset by $.02 due to lower gas margin, by $.05 due to higher operating expenses, by $.04 due to higher depreciation expense, by $.04 due to higher interest expense, by $.02 due to higher property taxes and by $.04 due to dilution from additional shares outstanding. 

Diluted Earnings Per Share

In May 2010, SCANA entered into equity forward contracts for the sale of approximately 6.6 million common shares. During periods when the average market price of SCANA’s common stock is above the per share adjusted forward sales price, the Company computes diluted earnings per share giving effect to this dilutive potential common stock using the treasury stock method. SCANA has extended the equity forward contracts and expects to settle them in the first quarter of 2013.

Dividends Declared

SCANA’s Board of Directors has declared the following dividends on common stock during 2012:

Declaration Date	Dividend Per Share	Record Date	Payment Date
February 15, 2012	$0.495	March 10, 2012	April 1, 2012
May 3, 2012	$0.495	June 11, 2012	July 1, 2012
August 2, 2012	$0.495	September 10, 2012	October 1, 2012
October 24, 2012	$0.495	December 10, 2012	January 1, 2013

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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	2012		% Change		2011		2012		% Change		2011
Operating revenues	$	716.2	(1.9	)%	$	730.2	$	1,857.6	(2.7	)%	$	1,908.2
Less:  Fuel used in generation	240.0		(13.6	)%	277.9		621.9		(16.3	)%	742.8
Purchased power	9.4		59.3	%	5.9		19.7		23.1	%	16.0
Margin	$	466.8	4.6	%	$	446.4	$	1,216.0	5.8	%	$	1,149.4

Third Quarter

Margin increased approximately $16.6 million due to base rate increases under the BLRA, by $3.3 million due to customer growth and higher average use and by $1.5 million due to lower fuel handling expenses.

Year to Date

Margin increased approximately $42.6 million due to base rate increases under the BLRA, by $16.4 million due to customer growth and higher average use and by $4.8 million due to lower fuel handling expenses.

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

		Third Quarter				Year to Date
Classification	2012	% Change		2011	2012	% Change		2011
Residential	2,372	(6.7	)%	2,542	5,861	(11.3	)%	6,609
Commercial	2,132	(2.2	)%	2,180	5,622	(2.5	)%	5,769
Industrial	1,531	(3.5	)%	1,586	4,430	(2.3	)%	4,536
Other	167	(1.2	)%	169	449	2.0	%	440
Total Retail Sales	6,202	(4.2	)%	6,477	16,362	(5.7	)%	17,354
Wholesale	677	9.4	%	619	1,935	19.6	%	1,618
Total Sales	6,879	(3.1	)%	7,096	18,297	(3.6	)%	18,972

Retail sales volume decreased for the periods shown primarily due to the effects of milder weather. The increase in wholesale sales for the periods shown is primarily due to higher contract utilization by a wholesale customer.

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	2012		% Change		2011		2012		% Change		2011
Operating revenues	$	107.0	(5.8	)%	$	113.6	$	507.0	(16.4	)%	$	606.2
Less:  Gas purchased for resale	53.4		(14.1	)%	62.2		239.2		(31.3	)%	348.0
Margin	$	53.6	4.3	%	$	51.4	$	267.8	3.7	%	$	258.2

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

		Third Quarter				Year to Date
Classification (in thousands)	2012	% Change		2011	2012	% Change		2011
Residential	1,883	1.6	%	1,853	20,052	(20.6	)%	25,253
Commercial	3,898	3.6	%	3,764	16,946	(8.3	)%	18,480
Industrial	4,939	13.3	%	4,359	15,410	9.8	%	14,032
Transportation	9,264	22.6	%	7,556	28,417	14.0	%	24,925
Total	19,984	14.0	%	17,532	80,825	(2.3	)%	82,690

Third Quarter

Margin at SCE&G increased primarily due to the SCPSC-approved increase in retail gas base rates under the RSA which became effective with the first billing cycle of November 2011. Margin at PSNC Energy increased by $0.9 million primarily due to residential and commercial customer growth of approximately 2% as well as increased industrial usage.  Total sales volumes increased due to higher industrial usage resulting from competitive natural gas prices, which also increased usage of natural gas fired electric generation.

Year to Date

Margin at SCE&G increased primarily due to the SCPSC-approved increase in retail gas base rates under the RSA which became effective with the first billing cycle of November 2011. Margin at PSNC Energy increased by $3.3 million primarily due to residential and commercial customer growth of approximately 2%.  Residential and commercial sales volumes decreased primarily as a result of milder weather. Industrial sales volumes increased due to the competitive price of gas versus alternate fuel sources.

Retail Gas Marketing

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

				Third Quarter							Year to Date
Millions	2012			% Change		2011			2012		% Change		2011
Operating revenues	$	63.7		(6.2	)%	$	67.9		$	287.8	(17.3	)%	$	348.0
Net Income (Loss)	(4.7		)	9.3	%	(4.3		)	3.2		(77.9	)%	14.5

Third Quarter

Changes in operating revenues and net loss are primarily due to lower gas prices and a decrease in regulated provider participants in 2012.

Year to Date

Changes in operating revenues and net income are primarily due to milder weather in 2012.

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	2012		% Change		2011		2012		% Change		2011
Operating revenues	$	186.7	(19.1	)%	$	230.7	$	485.8	(26.1	)%	$	657.2
Net Income	1.7		6.3	%	1.6		5.3		32.5	%	4.0

Operating revenues are lower due to lower market prices.  Net income is higher due to increases in consumption.

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Other Operating Expenses

Other operating expenses were as follows:

			Third Quarter						Year to Date
Millions of dollars	2012		% Change		2011		2012		% Change		2011
Other operation and maintenance	$	164.8	(1.1	)%	$	166.7	$	509.7	1.7	%	$	501.1
Depreciation and amortization	88.7		2.0	%	87.0		266.6		3.0	%	258.9
Other taxes	50.7		2.0	%	49.7		156.3		2.6	%	152.3

Third Quarter

Other operation and maintenance expenses decreased by $0.5 million due to lower generation, transmission and distribution expenses and by $2.5 million due to lower customer service expense and general expenses. These decreases were partially offset by $0.7 million due to higher compensation and other benefits. Depreciation and amortization expense increased primarily due to a higher level of plant in service.  Other taxes increased primarily due to higher property taxes.

Year to Date

Other operation and maintenance expenses increased by $9.8 million due to higher generation, transmission and distribution expenses and by $7.1 million due to higher compensation and other benefits. These increases were partially offset by $9.0 million due to lower customer service expense and general expenses, including bad debt expense. Depreciation and amortization expense increased primarily due to a higher level of plant in service.  Other taxes increased primarily due to higher property taxes.

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. 

Interest Expense

Interest charges increased primarily due to increased borrowings.

Income Taxes

Income taxes for the three and nine months ended September 30, 2012 were higher than the same periods in 2011 primarily due to higher income.

LIQUIDITY AND CAPITAL RESOURCES

The Company anticipates that its contractual 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, 2012 was 2.95 and 2.94, respectively.

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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, 2012, the Company had net available liquidity of approximately $1.1 billion. The Company's credit agreements were amended and extended in October 2012 and expire in October 2017. In connection with the amendment and extension of the agreements, Fuel Company's credit agreement was increased to $500 million, and the other companies' credit agreement remained the same size. In addition, SCE&G entered into a new three-year credit agreement in the amount of $200 million, which is scheduled to expire in October 2015. The amended and extended credit agreements, together with SCE&G's new three-year credit agreement, total an aggregate of $1.8 billion.The Company regularly monitors the commercial paper and short-term credit markets to optimize the timing of repayment of any outstanding balance on its draws 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 5.9%.  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.

SCE&G and GENCO have obtained FERC authority to issue short-term debt securities and assume liabilities as a guarantor (pursuant to Section 204 of the Federal Power Act). SCE&G may issue up to $2.2 billion of debt with maturity dates of one year or less, consisting of no more than $1.6 billion outstanding of short-term debt and no more than $600 million in liability as a guarantor, and GENCO may issue up to $150 million of short-term debt. The authority to make such issuances expires in October 2014.

SCANA issued $73 million of stock during the nine months ended September 30, 2012 through various compensation and dividend reinvestment plans.  Similar issuances are expected in future quarters. The Company expects to issue approximately 6.6 million common shares under forward sales contracts in the first quarter of 2013 which will result in net proceeds of approximately $196 million.

In July 2012, SCE&G issued $250 million of 4.35% first mortgage bonds due February 1, 2042 (issued at a premium with a yield to maturity of 3.86%), which constituted a reopening of $250 million of its 4.35% first mortgage bonds issued in January 2012. Proceeds from these sales were used to repay short-term debt primarily incurred as a result of our construction program, to finance capital expenditures and for general corporate purposes.

In January 2012, SCANA issued $250 million of 4.125% medium term notes due February 1, 2022. Proceeds from the sale were used to retire SCANA's $250 million 6.25% medium term notes due February 1, 2012.

The Company has paid approximately $37 million, net, in 2012 to settle interest rate contracts associated with the issuance of long-term debt.

OTHER MATTERS

Nuclear Generation

               SCE&G and Santee Cooper are parties to construction and operating agreements in which they agreed to be joint owners, and share operating costs and generation output, of two 1,117-MW nuclear generation units currently being constructed at the site of Summer Station, with SCE&G responsible for 55% of the cost and receiving 55% of the output, and Santee Cooper responsible for and receiving the remaining 45%.  Under these agreements, SCE&G has the primary responsibility for oversight of the construction of the New Units and will be responsible for the operation of the New Units as they come online. 

SCE&G, on behalf of itself and as agent for Santee Cooper, entered into the EPC Contract with the Consortium for the design, procurement and construction of the New Units.  SCE&G's share of the estimated cash outlays (future value, excluding AFC) totals approximately $6 billion for plant costs and related transmission infrastructure costs, which costs are projected based on historical one-year and five-year escalation rates as required by the SCPSC.

On March 30, 2012, the NRC approved and issued COLs for the New Units.  On April 19, 2012, SCE&G, on behalf of itself and as agent for Santee Cooper, issued a Full Notice to Proceed to the Consortium for construction of the New Units, allowing for the commencement of safety related aspects of the project.  The first New Unit is scheduled for substantial completion in March 2017, and the second New Unit is scheduled for substantial completion in May 2018.

34

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 structural 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. On July 11, 2012, SCE&G and the Consortium finalized an agreement which set SCE&G's portion of the costs for these specific claims at approximately $138 million (in 2007 dollars).  SCE&G anticipates that these additional costs, as well as other costs that may be identified from time to time, will be recoverable through rates.

On May 15, 2012, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost and construction schedule for the New Units.  This petition replaced a February 29, 2012 petition, which was withdrawn.  The updated capital cost schedule in this petition reflects an increase of $283 million (SCE&G's portion in 2007 dollars) over the cost approved in a May 2011 order. This petition includes additional identifiable capital costs of approximately $6 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, this petition includes revised substantial completion dates for the New Units based on the March 30, 2012 issuance of the COL and costs finalized in the July 11, 2012 agreement previously discussed.  The SCPSC approved the updated construction schedule and substantially all of the capital costs in this petition on November 7, 2012.

               When the NRC issued the COLs for the New Units, it imposed two conditions on the COLs, with the first requiring inspection and testing of certain components of the New Units' passive cooling system, and the second 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 tsunami resulting from a massive earthquake, which severely damaged several nuclear generating units and their back-up cooling systems in Japan.  SCE&G is evaluating the impact these conditions and requirements impose on the construction and operation of the New Units.  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.

As previously reported, SCE&G has been advised by Santee Cooper that it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation in the New Units.  Santee Cooper has entered into letters of intent with several parties that may result in one or more of them executing a power purchase agreement or acquiring a portion of Santee Cooper's ownership interest in the New Units.  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 commercial operation dates of the New Units.  Any such project cost increase or delay could be material.

For additional information related to environmental matters 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, 2011. 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

35

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 DT.  Fair value represents quoted market prices for these or similar instruments.

Expected Maturity:
Futures Contracts		Options
			Purchased Call
2012	Long	2012	(Long)
Settlement Price (a)	3.49	Strike Price (a)	4.03
Contract Amount (b)	5.2	Contract Amount (b)	11.5
Fair Value (b)	5.4	Fair Value (b)	0.3
2013		2013
Settlement Price (a)	3.79	Strike Price (a)	3.89
Contract Amount (b)	13.6	Contract Amount (b)	22.2
Fair Value (b)	14.4	Fair Value (b)	1.7
2014
Settlement Price (a)	4.16
Contract Amount (b)	1.1
Fair Value (b)	1.2
(a)  Weighted average, in dollars
(b)  Millions of dollars

Swaps	2012	2013	2014	2015	2016
Commodity Swaps:
Pay fixed/receive variable (b)	23.5	47.1	14.7	12.6	7.2
Average pay rate (a)	3.7615	4.2352	5.0123	5.2608	4.9875
Average received rate (a)	3.4855	3.8022	4.1823	4.3695	4.5463
Fair value (b)	21.8	42.3	12.3	10.5	6.5
Pay variable/receive fixed (b)	10.9	26.0	12.3	10.7	6.5
Average pay rate (a)	3.4721	3.8203	4.1767	4.3706	4.5463
Average received rate (a)	3.9605	4.4752	5.0134	5.2476	4.9942
Fair value (b)	12.4	30.5	14.7	12.8	7.2
Basis Swaps:
Pay variable/receive variable (b)	6.0	16.0	—	—	—
Average pay rate (a)	3.4740	3.8123	—	—	—
Average received rate (a)	3.4621	3.7975	—	—	—
Fair value (b)	6.0	15.9	—	—	—
(a) Weighted average, in dollars
(b) Millions of dollars

ITEM 4. CONTROLS AND PROCEDURES

As of September 30, 2012, 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, 2012, 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, 2012 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, 2012			December 31, 2011
Assets
Utility Plant In Service	$	9,904		$	10,312
Accumulated Depreciation and Amortization	(3,304		)	(3,367		)
Construction Work in Progress	1,908			1,472
Plant to be Retired, Net	418			—
Nuclear Fuel, Net of Accumulated Amortization	163			171
Utility Plant, Net ($644 and $662 related to VIEs)	9,089			8,588
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	58			52
Assets held in trust, net - nuclear decommissioning	94			84
Other investments	3			2
Nonutility Property and Investments, Net	155			138
Current Assets:
Cash and cash equivalents	35			16
Receivables, net of allowance for uncollectible accounts of $3 and $3	486			482
Affiliated receivables	11			9
Inventories (at average cost):
Fuel and gas supply	204			196
Materials and supplies	124			120
Emission allowances	2			2
Prepayments and other	139			82
Deferred income taxes	—			8
Total Current Assets ($201 and $193 related to VIEs)	1,001			915
Deferred Debits and Other Assets:
Regulatory assets	1,216			1,206
Other	169			190
Total Deferred Debits and Other Assets ($62 and $61 related to VIEs)	1,385			1,396
Total	$	11,630		$	11,037

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Millions of dollars	September 30, 2012		December 31, 2011
Capitalization and Liabilities
Common equity	$	3,864	$	3,665
Noncontrolling interest	112		108
Long-Term Debt, net	3,585		3,222
Total Capitalization	7,561		6,995
Current Liabilities:
Short-term borrowings	327		512
Current portion of long-term debt	169		19
Accounts Payable	188		231
Affiliated Payables	109		136
Customer deposits and customer prepayments	50		54
Taxes accrued	142		150
Interest accrued	53		54
Dividends declared	55		39
Derivative financial instruments	72		2
Other	35		61
Total Current Liabilities	1,200		1,258
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,437		1,371
Deferred investment tax credits	37		40
Asset retirement obligations	476		449
Postretirement benefits	183		179
Regulatory liabilities	649		575
Other	87		170
Total Deferred Credits and Other Liabilities	2,869		2,784
Commitments and Contingencies (Note 9)	—		—
Total	$	11,630	$	11,037

See Notes to Condensed Consolidated Financial Statements.

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited) 

	Three Months Ended September 30,						Nine Months Ended September 30,
Millions of dollars	2012			2011			2012			2011
Operating Revenues:
Electric	$	716		$	730		$	1,857		$	1,908
Gas	61			67			244			285
Total Operating Revenues	777			797			2,101			2,193
Operating Expenses:
Fuel used in electric generation	240			278			622			743
Purchased power	9			6			20			16
Gas purchased for resale	38			44			134			181
Other operation and maintenance	130			132			402			391
Depreciation and amortization	73			72			220			214
Other taxes	46			45			142			139
Total Operating Expenses	536			577			1,540			1,684
Operating Income	241			220			561			509
Other Income (Expense):
Other income	—			—			—			2
Other expenses	(3		)	(3		)	(9		)	(9		)
Interest charges, net of allowance for borrowed funds used during construction of $3, $2, $7 and $6	(53		)	(53		)	(157		)	(153		)
Allowance for equity funds used during construction	5			5			12			12
Total Other Expense	(51		)	(51		)	(154		)	(148		)
Income Before Income Tax Expense	190			169			407			361
Income Tax Expense	58			50			126			110
Net Income	132			119			281			251
Less Net Income Attributable to Noncontrolling Interest	3			2			9			7
Earnings Available to Common Shareholder	$	129		$	117		$	272		$	244
Dividends Declared on Common Stock	$	56		$	51		$	163		$	150

See Notes to Condensed Consolidated Financial Statements.

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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	2012			2011			2012			2011
Net Income	$	132		$	119		$	281		$	251
Other Comprehensive Income, net of tax:
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax of $-, $-, $- and $-	—			—			—			—
Total Comprehensive Income	132			119			281			251
Less comprehensive income attributable to noncontrolling interest	(3		)	(2		)	(9		)	(7		)
Comprehensive income available to common shareholder (1)	$	129		$	117		$	272		$	244

(1)  Accumulated other comprehensive loss totaled $3.1 million as of September 30, 2012 and $3.3 million as of December 31, 2011.

See Notes to Condensed Consolidated Financial Statements.

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SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
Millions of dollars	2012			2011
Cash Flows From Operating Activities:
Net income	$	281		$	251
Adjustments to reconcile net income to net cash provided from operating activities:
Losses from equity method investments	3			2
Deferred income taxes, net	74			83
Depreciation and amortization	221			214
Amortization of nuclear fuel	38			27
Allowance for equity funds used during construction	(12		)	(12		)
Cash provided (used) by changes in certain assets and liabilities:
Receivables	(22		)	11
Inventories	(49		)	20
Prepayments and other	(57		)	63
Regulatory assets	(1		)	(90		)
Regulatory liabilities	49			(10		)
Accounts payable	13			(40		)
Taxes accrued	(8		)	(14		)
Interest accrued	(1		)	(1		)
Changes in other assets	44			(7		)
Changes in other liabilities	(20		)	6
Net Cash Provided From Operating Activities	553			503
Cash Flows From Investing Activities:
Property additions and construction expenditures	(793		)	(641		)
Proceeds from investments (including derivative collateral posted)	196			5
Purchase of investments (including derivative collateral posted)	(199		)	(37		)
Proceeds from interest rate contract settlement	14			—
Payments upon interest rate contract settlement	—			(31		)
Net Cash Used For Investing Activities	(782		)	(704		)
Cash Flows From Financing Activities:
Proceeds from issuance of long-term debt	517			349
Repayment of long-term debt	(13		)	(166		)
Dividends	(146		)	(155		)
Contributions from parent	84			73
Short-term borrowings –affiliate, net	(9		)	(30		)
Short-term borrowings, net	(185		)	116
Net Cash Provided From Financing Activities	248			187
Net Increase (Decrease) In Cash and Cash Equivalents	19			(14		)
Cash and Cash Equivalents, January 1	16			31
Cash and Cash Equivalents, September 30	$	35		$	17
Supplemental Cash Flow Information:
Cash paid for– Interest (net of capitalized interest of $7 and $6)	$	147		$	138
– Income taxes	81			—
Noncash Investing and Financing Activities:
Accrued construction expenditures	66			56
Capital leases	4			2

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, 2012 and 2011

(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, 2011.  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

Variable Interest Entity

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

GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $480 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

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.

New Accounting Matters

Effective for the first quarter of 2012, Consolidated SCE&G adopted accounting guidance that revises how comprehensive income is presented in its financial statements. The adoption of this guidance has not impacted, and is not expected to impact, Consolidated SCE&G's results of operations, cash flows or financial position.

Effective for the first quarter of 2012, Consolidated SCE&G adopted accounting guidance that amended existing requirements for measuring fair value and for disclosing information about fair value measurements.  The adoption of this guidance has not impacted, and is not expected to impact, Consolidated SCE&G's results of operations, cash flows or financial position.

2. RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric

SCE&G's retail electric rates are established in part by using 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 February 2012, SCE&G requested authorization to decrease the total fuel cost component of its retail electric rates to be effective the first billing cycle of May 2012. In March 2012, SCE&G, the ORS and SCEUC entered into a settlement agreement in which SCE&G agreed to recover an amount equal to its actual under-collected balance of base fuel and variable environmental costs as of April 30, 2012

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in the next rate period beginning with the first billing cycle of May 2012. In April 2012, the SCPSC approved the settlement agreement and ruled among other matters that SCE&G's fuel purchasing practices and policies were reasonable and prudent for the period January 1, 2011, through December 31, 201l.

On June 29, 2012, SCE&G filed an application with the SCPSC requesting an increase in retail revenues of approximately $151.5 million or 6.61%. SCE&G also requested a mid-period reduction to the cost of fuel component in rates, as well as a reduction in the DSM component rider to retail rates. These adjustments will reduce the overall revenue increase requested to 3.75%. In addition, SCE&G requested recovery of and a return on the net carrying value of certain generating plant assets described below. SCE&G has requested that the proposed increase be effective January 1, 2013. A public hearing on this matter has been scheduled to begin on November 26, 2012; a decision from the SCPSC is expected in late December 2012.

On May 30, 2012, SCE&G filed its annual 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 plans to retire by 2018, subject to future developments in environmental regulations, among other matters. These units have an aggregate generating capacity (summer 2012) of 730 MW. The net carrying value of these units totaled $418 million at September 30, 2012, and is identified as Plant to be Retired, Net in the condensed consolidated financial statements. Included in this amount is approximately $23 million related to a unit that SCE&G plans to retire by the end of 2012. In its June 29, 2012 application with the SCPSC, described above, SCE&G has requested recovery of and a return on the net carrying value of this unit. SCE&G plans to make similar requests for the remaining units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. SCE&G continues to depreciate these units using composite straight-line rates approved by the SCPSC while the assets are in use.

In July 2010, the SCPSC issued an order approving a 4.88% overall increase in SCE&G’s retail electric base rates and authorized an allowed return on common equity of 10.7%. The SCPSC’s order adopted various stipulations among SCE&G, the ORS and other intervening parties. Among other matters, the SCPSC’s order provided for a $48.7 million credit to SCE&G’s customers over two years to be offset by accelerated recognition of previously deferred state income tax credits.

The SCPSC has approved DSM Programs for SCE&G's customers, including the establishment of an annual rider, approved by the SCPSC, to allow recovery of the costs and lost net margin revenue associated with the DSM Programs, along with an incentive for investing in such programs. SCE&G must submit annual filings to the SCPSC regarding the DSM Programs, net lost revenues, program costs, incentives and net program benefits.  In January 2011, SCE&G submitted to the SCPSC an annual update on DSM Programs and rate rider. In May 2011, the SCPSC approved the updated rate rider, which became effective the first billing cycle of June 2011. In January 2012, SCE&G submitted to the SCPSC another annual update on DSM Programs and rate rider. In April 2012, the SCPSC approved the updated rate rider and authorized SCE&G to increase its rates to recover approximately $19.6 million related to DSM Programs as set forth in its petition. The increase became effective the first billing cycle of May 2012.

Electric – BLRA

The SCPSC has approved SCE&G's combined application pursuant to the BLRA seeking a certificate of environmental compatibility and public convenience and necessity and for a base load review order relating to the proposed construction and operation by SCE&G and Santee Cooper of the New Units at Summer Station.  Under the BLRA, the SCPSC conducted a full pre-construction prudency review of the proposed units and the engineering, procurement, and construction contract under which they are being built.  The SCPSC prudency finding is binding on all future related rate proceedings so long as the construction proceeds in accordance with schedules, estimates and projections, as approved by the SCPSC.

In May 2011, the SCPSC approved an updated capital cost schedule sought by SCE&G that, among other matters, incorporated then-identifiable capital costs of $173.9 million (SCE&G's portion in 2007 dollars). On May 15, 2012, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost and construction schedule for the New Units. This petition replaced a February 29, 2012 petition, which was withdrawn. The updated capital cost schedule in this petition reflects an increase of $283 million (SCE&G's portion in 2007 dollars) over the cost approved in the May 2011 order.  This petition includes additional identifiable capital costs of approximately $6 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, this petition includes revised substantial completion dates for the New Units based on the March 30,

44

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 (which claims are discussed in Note 9).  The SCPSC approved the updated construction schedule and substantially all of the capital costs in this petition on November 7, 2012.

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 following years:

Year	Increase	Amount (Millions)
2012	2.3%	$52.1
2011	2.4%	$52.8

Gas

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

Year	Action			Amount (Millions)
2012	2.1	%	Increase	$7.5
2011	2.1	%	Increase	$8.6

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 annual PGA hearing to review SCE&G's gas purchasing policies and procedures was held in November 2011 before the SCPSC. The SCPSC issued an order in January 2012 finding that SCE&G's gas purchasing policies and practices during the review period of August 1, 2010 through July 31, 2011, were reasonable and prudent and authorized the suspension of SCE&G's natural gas hedging program. The next annual PGA hearing is scheduled for November 8, 2012.

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 of our 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, 2012		December 31, 2011
Regulatory Assets:
Accumulated deferred income taxes	$	238	$	238
Under collections – electric fuel adjustment clause	—		28
Environmental remediation costs	39		25
AROs and related funding	305		301
Franchise agreements	37		40
Deferred employee benefit plan costs	347		348
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	159		154
Deferred pollution control costs	35		25
Other	56		41
Total Regulatory Assets	$	1,216	$	1,206

Regulatory Liabilities:
Accumulated deferred income taxes	$	21	$	23
Asset removal costs	507		493
Storm damage reserve	27		32
Deferred gains on interest rate derivatives	85		26
Planned major maintenance	8		—
Other	1		1
Total Regulatory Liabilities	$	649	$	575

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 expected to be recovered in retail electric rates over periods exceeding 12 months. 

Environmental remediation costs represent costs associated with the assessment and clean-up of MGP sites currently or formerly owned by SCE&G.  These regulatory assets are expected to be recovered over periods of up to approximately 28 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 95 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 amountsof 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.  A significant majority of these deferred costs are expected to be recovered through utility rates over average service periods of participating employees, or up to approximately 12 years.

Planned major maintenance related to certain fossil hydro 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 hydro turbine/generation equipment maintenance.  Nuclear refueling charges are accrued during each 18-month refueling outage cycle as a component of cost of service.

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Deferred losses or gains on interest rate derivatives represent the effective portions of changes in fair value and payments made or received upon termination of certain interest rate derivatives designated as cash flow hedges.  These amounts are expected to be amortized to interest expense over the lives of the underlying debt, up to approximately 30 years.

Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the installation of scrubbers at Wateree and Williams Stations pursuant to specific regulatory orders.  Such costs related to Williams Station amount to $9.1 million at September 30, 2012 and are being recovered through utility rates over approximately 30 years. The remaining costs relate to Wateree Station and SCE&G is allowed to accrue interest on these deferred costs until such costs are approved for recovery by the SCPSC.

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, certain transmission and distribution insurance premiums and certain tree trimming and vegetation management expenditures in excess of amounts included in base rates.  During the nine months ended September 30, 2012 and 2011, SCE&G applied costs of $4.6 million and $3.6 million, respectively, to the reserve.  Pursuant to the SCPSC’s July 2010 retail electric rate order approving an electric rate increase, SCE&G 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 FERC. In recording such costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders received by SCE&G. The costs are currently not being recovered, but are expected to be recovered through rates in future periods. In the future, as a result of deregulation or other changes in the regulatory environment or changes in accounting requirements, Consolidated SCE&G could be required to write off its regulatory assets and liabilities. Such an event could have a material effect on Consolidated SCE&G's results of operations, liquidity or financial position in the period the write-off would be recorded.

3. EQUITY

Changes in common equity during the nine months ended September 30, 2012 and 2011 were as follows:

Millions of dollars	Common Equity			Noncontrolling Interest			Total Equity
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
Balance at January 1, 2011	$	3,437		$	104		$	3,541
Capital contribution from parent	73			—			73
Dividends declared	(146		)	(5		)	(151		)
Comprehensive income	244			7			251
Balance as of September 30, 2011	$	3,608		$	106		$	3,714

Authorized shares of SCE&G common stock were 50 million as of September 30, 2012 and December 31, 2011.  Outstanding shares of common stock were 40.3 million at both September 30, 2012 and December 31, 2011. Authorized shares of SCE&G preferred stock were 20 million as of September 30, 2012 and December 31, 2011, 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 were held by SCANA during all periods presented.

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4. LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

     In July 2012, SCE&G issued $250 million of 4.35% first mortgage bonds due February 1, 2042, which constituted a reopening of $250 million of its 4.35% first mortgage bonds issued in January 2012. Proceeds from these sales were used to repay short-term debt primarily incurred as a result of SCE&G's construction program, to finance capital expenditures and for general corporate purposes.

 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, 2012			December 31, 2011
Lines of credit:
Committed long-term
Total	$	1,100		$	1,100
LOC advances	—			—
Weighted average interest rate	—			—
Outstanding commercial paper (270 or fewer days)	$	327		$	512
Weighted average interest rate	0.47		%	0.56		%
Letters of credit supported by LOC	$	0.3		$	0.3
Available	$	773		$	588

At September 30, 2012, SCE&G and Fuel Company were parties to credit agreements in the amount of $1.1 billion, of which $400 million relates to Fuel Company. These credit agreements were 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, fossil fuel, and emission and other environmental allowances.  As of September 30, 2012, Wells Fargo Bank, National Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provided 10.0% of the aggregate $1.1 billion credit facilities, Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A. and UBS Loan Finance LLC each provided 8.0%, and Deutsche Bank AG New York Branch, Union Bank, N.A. and U.S. Bank National Association each provided 5.3%.  Three other banks provided the remaining 6.0%.

These credit agreements were amended and extended in October 2012 to expire in October 2017. In connection with the amendment and extension of the agreements, the amount of Fuel Company's credit agreement was increased to $500 million, and SCE&G's existing credit agreement remained the same size. In addition, SCE&G entered into a new three-year credit agreement in the amount of $200 million, which is scheduled to expire in October 2015. The amended and extended credit agreements, together with SCE&G's new three-year credit agreement total an aggregate of $1.4 billion. Wells Fargo Bank, National Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provide 10.7% of the aggregate 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 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.

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5. INCOME TAXES

In connection with a change in method of tax accounting for certain repair costs, Consolidated SCE&G had previously recorded approximately $38 million of unrecognized tax benefit. During the first quarter of 2012, newadministrative guidance from the Internal Revenue Service was published. Under this guidance, Consolidated SCE&G has recognized the entire $38 million of unrecognized tax benefit. Since this change was primarily a temporary difference, the recognition of this benefit did not have a significant effect on Consolidated SCE&G's effective tax rate. No other material changes in the status of Consolidated SCE&G's tax positions have occurred through September 30, 2012.

Consolidated SCE&G recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses. In connection with the recognition of tax benefits described above, during the quarter ended March 31, 2012, Consolidated SCE&G reversed $2 million of interest expense which had been accrued during 2011. 

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.  The fair value of derivative instruments is determined by reference to quoted market prices of listed contracts, published quotations or, for interest rate swaps, discounted cash flow models with independently sourced data.

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 Board of Directors with regard to the management of risk and brings to the Board’s attention any 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 SCPSC authorized the suspension of SCE&G's natural gas hedging program in January 2012.  The fair value of such derivative instruments remaining to be settled were not significant for any period presented.

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 and are classified as an operating activity for cash flow purposes.

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.  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 and are classified as an operating activity for cash flow purposes.  Ineffective portions are recognized in income.  Cash payments made or received upon termination of these financial instruments are classified as an investing activity for cash flow purposes.

Quantitative Disclosures Related to Derivatives

SCE&G was party to natural gas derivative contracts for 210,000 DT at September 30, 2012 and 2,490,000 DT at December 31, 2011.  Consolidated SCE&G was a party to interest rate swaps designated as cash flow hedges with an aggregate notional amount of $971.4 million at September 30, 2012 and $471.4 million at December 31, 2011.

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, 2012
Derivatives designated as hedging instruments
Interest rate contracts	Prepayments and other	$	27	Other current liabilities	$	72
	Other deferred debits and other assets	20		Other deferred credits and other liabilities	12
Total		$	47		$	84
As of December 31, 2011
Derivatives designated as hedging instruments
Interest rate contracts	Prepayments and other	$	1	Other current liabilities	$	2
				Other deferred credits and other liabilities	75
Total		$	1		$	77

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

						Gain (Loss) Reclassified from
Derivatives in Cash Flow	Gain (Loss) Deferred					Deferred Accounts into Income
Hedging Relationships	in Regulatory Accounts					(Effective Portion)
Millions of dollars	(Effective Portion)					Location	Amount
	2012		2011				2012			2011
Three Months Ended September 30,
Interest rate contracts	$	23	$	(63	)	Interest expense	$	(1	)	$	(1	)
Nine Months Ended September 30,
Interest rate contracts	$	51	$	(72	)	Interest expense	$	(2	)	$	(2	)

Derivatives not designated as Hedging Instruments	Gain (Loss) Recognized in Income
Millions of dollars	Location	2012		2011
Three Months Ended September 30,
Commodity contracts	Gas purchased for resale	—		—
Nine Months Ended September 30,
Commodity contracts	Gas purchased for resale	(1	)	(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, 2012 and were $0.8 million and $1.1 million for the three and nine months ended September 30, 2011, respectively.

Credit Risk Considerations

Consolidated SCE&G 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, 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, surety bonds, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. the collateral agreements require a counterparty to post cash, surety bonds 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 require Consolidated SCE&G to provide collateral upon the occurrence of specific events, primarily credit downgrades.  As of September 30, 2012 and December 31, 2011, Consolidated SCE&G has posted $42.7 million and $45.0 million, respectively, of collateral related to derivatives with contingent provisions that are 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 the noncurrent positions are recorded in Other within Deferred Debits and Other Assets on the consolidated balance sheets. If all of the contingent features underlying these instruments were fully triggered as of September 30, 2012 and December 31, 2011, Consolidated SCE&G would be required to post an additional $28.0 million and $31.7 million, respectively, of collateral to its counterparties.  The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of September 30, 2012 and December 31, 2011 is $70.7 million and $76.7 million, respectively.

In addition, as of September 30, 2012 and December 31, 2011, 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, 2012 and December 31, 2011, Consolidated SCE&G could request $45.8 million and $1.1 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, 2012 and December 31, 2011 is $45.8 million and $1.1 million, respectively.

7. FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

Consolidated SCE&G’s interest rate swap agreements are valued using discounted cashflow models with independently sourced market 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, 2012	December 31, 2011
Assets -	Interest rate contracts	$47	$1
Liabilities -	Interest rate contracts	84	77

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 and 2 during any period presented.

Financial instruments for which the carrying amount may not equal estimated fair value at September 30, 2012 and December 31, 2011 were as follows:

	September 30, 2012				December 31, 2011
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	3,753.6	$	4,661.0	$	3,241.5	$	3,920.3

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

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

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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	2012			2011			2012		2011
Three months ended September 30,
Service cost	$	4.1		$	3.6		$	0.8	$	0.7
Interest cost	9.1			8.8			2.3		2.5
Expected return on assets	(12.6		)	(13.0		)	—		—
Prior service cost amortization	1.6			1.5			0.1		0.2
Amortization of actuarial loss	3.7			2.6			0.1		0.1
Net periodic benefit cost	$	5.9		$	3.5		$	3.3	$	3.5
Nine months ended September 30,
Service cost	$	11.8		$	11.0		$	2.8	$	2.5
Interest cost	27.3			27.7			7.0		7.2
Expected return on assets	(37.8		)	(40.5		)	—		—
Prior service cost amortization	4.5			4.5			0.5		0.6
Amortization of actuarial loss	11.7			7.7			0.3		0.2
Net periodic benefit cost	$	17.5		$	10.4		$	10.6	$	10.5

No contribution to the pension trust will be necessary in or for 2012, nor will limitations on benefit payments apply.   As authorized by the SCPSC, SCE&G defers all pension expense related to retail electric and gas operations as a regulatory asset. Costs totaling $4.0 million and $11.4 million were deferred for the three and nine months ended September 30, 2012, respectively. Costs totaling $2.2 million and $6.8 million were deferred for the corresponding periods in 2011.  

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 $12.6 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 $117.5 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $17.5 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 $78.3 million per incident, but not more than $11.7 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 policies (for itself and on behalf of Santee Cooper) with NEIL.  The policies provide coverage to the nuclear facility for property damage and outage costs up to $2.75 billion. 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. 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 $37.3 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, 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

On April 13, 2012, the EPA issued a proposed rule to establish a new source performance standard for GHG emissions from fossil fuel-fired electric generating units. If enacted, the proposed rule will limit emissions of carbon dioxide from new fossil fuel-fired electric utility generating units.  Consolidated SCE&G is evaluating the proposed rule, but cannot predict when the rule will become final, if at all, or what conditions it 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, including South Carolina, 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 would have replaced CAIR and the Clean Air Transport Rule proposed in July 2010 and was aimed at addressing power plant emissions that may contribute to air pollution in other states.  The rule would have required 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 U.S. Court of Appeals for the D.C. Circuit vacated CSAPR and left CAIR in place. On October 5, 2012, the EPA filed a petition for rehearing of the U. S. Court of Appeals order. Air quality control installations that SCE&G and GENCO have already completed 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 CAIR or other rules issued by the EPA are expected to be recoverable through rates.

In 2005, the EPA issued the CAMR which established a mercury emissions cap and trade program for coal-fired power plants. Numerous parties challenged the rule and, on February 8, 2008, the United States Circuit Court for the District of Columbia vacated the rule for electric utility steam generating units.  In March 2011, the EPA proposed new standards for mercury and other specified air pollutants. The rule containing the proposed new standards, which became effective on April 16, 2012, provides up to four years for facilities to meet the standards. The rule is currently being evaluated by Consolidated SCE&G. 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 enactment of these environmental regulations, along with other factors, has resulted in the inclusion in SCE&G's most recently filed IRP of its plans to retire a total of six coal-fired units by 2018, subject to future developments in environmental regulations, among other matters.

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.  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.  SCE&G defers site assessment and cleanup costs and expects to recover them through rates. 

SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals.  These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC and the EPA.  SCE&G anticipates that major remediation activities at all these sites will continue until 2015 and will cost an additional $22.4 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 and insurance settlements.  At September 30, 2012, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $38.6 million and are included in regulatory assets.

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Nuclear Generation

SCE&G and Santee Cooper are parties to construction and operating agreements in which they agreed to be joint owners, and share operating costs and generation output, of two1,117-MW nuclear generation units currently being constructed at the site of Summer Station, with SCE&G responsible for 55% of the cost and receiving 55% of the output, and Santee Cooper responsible for and receiving the remaining 45%.  Under these agreements, SCE&G has the primary responsibility for oversight of the construction of the New Units and will be responsible for the operation of the New Units as they come online. 

SCE&G, on behalf of itself and as agent for Santee Cooper, entered into the EPC Contract with the Consortium for the design, procurement and construction of the New Units.  SCE&G's share of the estimated cash outlays (future value, excluding AFC) totals approximately $6 billion for plant costs and related transmission infrastructure costs, which costs are projected based on historical one-year and five-year escalation rates as required by the SCPSC.

On March 30, 2012, the NRC approved and issued COLs for the New Units.  On April 19, 2012, SCE&G, on behalf of itself and as agent for Santee Cooper, issued a Full Notice to Proceed to the Consortium for construction of the New Units, allowing for the commencement of safety related aspects of the project.  The first New Unit is scheduled for substantial completion in March 2017, and the second New Unit is scheduled for substantial completion in May 2018.

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 structural 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. On July 11, 2012, SCE&G and the Consortium finalized an agreement which set SCE&G's portion of the costs for these specific claims at approximately $138 million (in 2007 dollars).  SCE&G anticipates that these additional costs, as well as other costs that may be identified from time to time, will be recoverable through rates.

On May 15, 2012, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost and construction schedule for the New Units.  This petition replaced a February 29, 2012 petition, which was withdrawn. The updated capital cost schedule in this petition reflects an increase of $283 million (SCE&G's portion in 2007 dollars) over the cost approved in the May 2011 order.  This petition includes additional identifiable capital costs of approximately $6 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, this petition includes revised substantial completion dates for the New Units based on the March 30, 2012 issuance of the COL and costs finalized in the July 11, 2012 agreement previously discussed. The SCPSC approved the updated construction schedule and substantially all of the capital costs in this petition on November 7, 2012.

When the NRC issued the COLs for the New Units, it imposed two conditions on the COLs, with the first requiring inspection and testing of certain components of the New Units' passive cooling system, and the second 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 tsunami resulting from a massive earthquake, which severely damaged several nuclear generating units and their back-up cooling systems in Japan.  SCE&G is evaluating the impact these conditions and requirements impose on the construction and operation of the New Units.  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.

As previously reported, SCE&G has been advised by Santee Cooper that it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation in the New Units.  Santee Cooper has entered into letters of intent with several parties that may result in one or more of them executing a power purchase agreement or acquiring a portion of Santee Cooper's ownership interest in the New Units.  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 commercial operation dates of the New Units.  Any such project cost increase or delay could be material.

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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 $27.1 million and $22.8 million for the nine months ended September 30, 2012 and 2011, respectively.  SCE&G had approximately $2.8 million and $2.5 million payable to CGT for transportation services at September 30, 2012 and December 31, 2011, 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 $84.0 million and $146.6 million for the nine months ended September 30, 2012 and 2011, respectively.  SCE&G’s payables to SEMI for such purposes were $10.1 million and $13.2 million as of September 30, 2012 and December 31, 2011, respectively.

SCE&G owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and selling of refined coal to reduce emissions. SCE&G owned 10% of Cope Refined Coal, LLC through December 31, 2011. SCE&G accounts for these investments using the equity method.  SCE&G’s receivables from these affiliates were $10.8 million at September 30, 2012 and $8.5 million at December 31, 2011.  SCE&G’s payables to these affiliates were $10.8 million at September 30, 2012 and $8.6 million at December 31, 2011.  SCE&G’s total purchases were $87.3 million and $100.9 million for the nine months ended September 30, 2012 and 2011, respectively.  SCE&G’s total sales were $86.9 million and $100.5 million for the nine months ended September 30, 2012 and 2011, respectively.

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 the nine months ended September 30, 2012 or 2011.  At September 30, 2012 and December 31, 2011, Consolidated SCE&G owed an affiliate $49.3 million and $58.5 million, respectively.

An affiliate processes and pays invoices for Consolidated SCE&G and is reimbursed by them. Consolidated SCE&G owed $45 million and $43 million to the affiliate at September 30, 2012 and December 31, 2011, respectively, for invoices paid by the affiliate on behalf of Consolidated SCE&G.

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.

			Operating			Earnings Available
	External		Income			To Common
Millions of dollars	Revenue		(Loss)			Shareholder
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

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Three Months Ended September 30, 2011
Electric Operations	$	730	$	225		n/a
Gas Distribution	67		(5		)	n/a
Adjustments/Eliminations	—		—			$	117
Consolidated Total	$	797	$	220		$	117
Nine Months Ended September 30, 2011
Electric Operations	$	1,908	$	487		n/a
Gas Distribution	285		23			n/a
Adjustments/Eliminations	—		(1		)	$	244
Consolidated Total	$	2,193	$	509		$	244

	September 30,		December 31,
Segment Assets	2012		2011
Electric Operations	$	8,750	$	8,222
Gas Distribution	648		622
Adjustments/Eliminations	2,232		2,193
Consolidated Total	$	11,630	$	11,037

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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, 2011. 

RESULTS OF OPERATIONS

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2012

AS COMPARED TO THE CORRESPONDING PERIODS IN 2011

Net Income

Net income for Consolidated SCE&G was as follows:

			Third Quarter						Year to Date
Millions of dollars	2012		% Change		2011		2012		% Change		2011
Net income	$	132.2	10.6	%	$	119.5	$	281.5	12.1	%	$	251.1

Third Quarter

Net income increased by $14.1 million due to higher electric margin, by $0.8 million due to higher gas margin and by $1.5 million due to lower operation and maintenance expenses.  This increase was partially offset by higher depreciation expense of $0.8 million, higher property taxes of $0.9 million and higher interest expense of $0.7 million.

Year to Date

Net income increased by $45.9 million due to higher electric margin and by $4.3 million due to higher gas margin.  This increase was partially offset by $6.3 million due to higher operation and maintenance expenses, higher depreciation expense of $4.3 million, higher property taxes of $2.8 million and higher interest expense of $3.0 million.

Dividends Declared

Consolidated SCE&G’s Boards of Directors declared the following dividends on common stock (all of which was held by SCANA) during 2012:

Declaration Date	Amount	Quarter Ended	Payment Date
February 15, 2012	$53.4 million	March 31, 2012	April 1, 2012
May 3, 2012	$54.1 million	June 30, 2012	July 1, 2012
August 2, 2012	$55.8 million	September 30, 2012	October 1, 2012
October 24, 2012	$45.6 million	December 31, 2012	January 1, 2013

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		2012		% Change		2011		2012		% Change		2011
Operating revenues		$	716.2	(1.9	)%	$	730.2	$	1,857.6	(2.7	)%	$	1,908.2
Less:	Fuel used in electric generation	240.0		(13.6	)%	277.9		621.9		(16.3	)%	742.8
	Purchased power	9.4		59.3	%	5.9		19.7		23.1	%	16.0
Margin		$	466.8	4.6	%	$	446.4	$	1,216.0	5.8	%	$	1,149.4

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Third Quarter

Margin increased approximately $16.6 million due to base rate increases under the BLRA, by $3.3 million due to customer growth and higher average use and by $1.5 million due to lower fuel handling expenses.

Year to Date

Margin increased approximately $42.6 million due to base rate increases under the BLRA, by $16.4 million due to customer growth and higher average use and by $4.8 million due to lower fuel handling expenses.

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

		Third Quarter				Year to Date
Classification	2012	% Change		2011	2012	% Change		2011
Residential	2,372	(6.7	)%	2,542	5,861	(11.3	)%	6,609
Commercial	2,132	(2.2	)%	2,180	5,622	(2.5	)%	5,769
Industrial	1,531	(3.5	)%	1,586	4,430	(2.3	)%	4,536
Other	167	(1.2	)%	169	449	2.0	%	440
Total Retail Sales	6,202	(4.2	)%	6,477	16,362	(5.7	)%	17,354
Wholesale	677	9.4	%	619	1,935	19.6	%	1,618
Total Sales	6,879	(3.1	)%	7,096	18,297	(3.6	)%	18,972

Retail sales volume decreased for the periods shown primarily due to the effects of milder weather. The increase in wholesale sales volumes for the periods shown is primarily due to higher contract utilization by a wholesale customer.

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	2012		% Change		2011		2012		% Change		2011
Operating revenues	$	61.5	(8.5	)%	$	67.2	$	243.9	(14.3	)%	$	284.7
Less: Gas purchased for resale	37.6		(15.7	)%	44.6		133.9		(26.0	)%	180.9
Margin	$	23.9	5.8	%	$	22.6	$	110.0	6.0	%	$	103.8

Third Quarter

Margin increased primarily due to the SCPSC-approved increase in retail gas base rates under the RSA which became effective with the first billing cycle of November 2011.

Year to Date

Margin increased primarily due to the SCPSC-approved increase in retail gas base rates under the RSA which became effective with the first billing cycle of November 2011.

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

		Third Quarter				Year to Date
Classification (in thousands)	2012	% Change		2011	2012	% Change		2011
Residential	648	(1.4	)%	657	6,159	(24.5	)%	8,162
Commercial	2,188	1.0	%	2,166	8,230	(6.7	)%	8,823
Industrial	4,554	10.7	%	4,114	14,021	11.3	%	12,602
Transportation	1,055	9.1	%	967	3,471	8.9	%	3,186
Total	8,445	6.8	%	7,904	31,881	(2.7	)%	32,773

Third Quarter

Total sales volumes increased due to increased industrial sales as a result of the competitive price of gas versus alternate fuel sources.

Year to Date

Residential and commercial sales volumes decreased primarily as a result of milder weather. Industrial sales volumes increased due to the competitive price of gas versus alternate fuel sources.

Other Operating Expenses

Other operating expenses were as follows:

			Third Quarter						Year to Date
Millions of dollars	2012		% Change		2011		2012		% Change		2011
Other operation and maintenance	$	130.1	(1.2	)%	$	131.7	$	402.2	2.8	%	$	391.2
Depreciation and amortization	73.0		1.5	%	71.9		219.8		2.8	%	213.8
Other taxes	46.4		1.8	%	45.6		142.2		1.8	%	139.7

Third Quarter 

Other operation and maintenance expenses decreased primarily due to lower compensation and benefits. Depreciation and amortization expense increased primarily due to a higher level of plant in service.  Other taxes increased primarily due to higher property taxes.

Year to Date

Other operation and maintenance expenses increased by $9.5 million due to higher generation, transmission and distribution expenses and by $2.6 million due to higher compensation and benefits. These increases were partially offset by $4.1 million due to lower customer service expenses and general expenses. Depreciation and amortization expense increased primarily due to a higher level of plant in service.  Other taxes increased primarily due to higher property taxes.

Other Income (Expense)

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

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Interest Expense

Interest charges increased primarily due to increased borrowings.

Income Taxes

Income taxes for the three and nine months ended September 30, 2012 were higher than the same period in 2011 primarily due to higher income.

LIQUIDITY AND CAPITAL RESOURCES

Consolidated SCE&G anticipates that its contractual cash obligations will be met through internally generated funds and the incurrence of additional short- and long-term indebtedness.  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, 2012 was 3.46 and 3.30, respectively.

 Consolidated SCE&G is obligated with respect to an aggregate of $67.8 million of industrial revenue bonds which are secured by letters of credit issued by Branch Banking and Trust Company.  These letters of credit expire, subject to renewal, in the fourth quarter of 2014.

At September 30, 2012, Consolidated SCE&G had net available liquidity of approximately $807.6 million. Consolidated SCE&G's credit agreements were amended and extended in October 2012 and expire in October 2017. In connection with the amendment and extension of the agreements, Fuel Company's credit agreement was increased to $500 million, and SCE&G's existing credit agreement remained the same size. In addition, SCE&G entered into a new three-year credit agreement in the amount of $200 million, which is scheduled to expire in October 2015. Consolidated SCE&G regularly monitors the commercial paper and short-term credit markets to optimize the timing of repayment of any outstanding balance on its draws from the credit facilities.  Consolidated SCE&G’s long term debt portfolio has a weighted average maturity of approximately 19 years and bears an average interest cost of 5.9%.  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 and GENCO have obtained FERC authority to issue short-term debt securities and assume liabilities as a guarantor (pursuant to Section 204 of the Federal Power Act). SCE&G may issue up to $2.2 billion of debt with maturity dates of one year or less, consisting of no more than $1.6 billion outstanding of short-term debt and no more than $600 million in liability as a guarantor, and GENCO may issue up to $150 million of short-term debt. The authority to make such issuances expires in October 2014.

In July 2012, SCE&G issued $250 million of 4.35% first mortgage bonds due February 1, 2042 (issued at a premium with a yield to maturity of 3.86%), which constituted a reopening of $250 million of its 4.35% first mortgage bonds issued in January 2012. Proceeds from these sales were used to repay short-term debt primarily incurred as a result of our construction program, to finance capital expenditures and for general corporate purposes.

SCE&G has received approximately $14 million in 2012 from the settlement of interest rate contracts associated with the issuance of long-term debt.

OTHER MATTERS

Nuclear Generation

               SCE&G and Santee Cooper are parties to construction and operating agreements in which they agreed to be joint owners, and share operating costs and generation output, of two 1,117-MW nuclear generation units currently being constructed at the site of Summer Station, with SCE&G responsible for 55% of the cost and receiving 55% of the output, and Santee Cooper responsible for and receiving the remaining 45%.  Under these agreements, SCE&G has the primary responsibility for oversight of the construction of the New Units and will be responsible for the operation of the New Units as they come online. 

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SCE&G, on behalf of itself and as agent for Santee Cooper, entered into the EPC Contract with the Consortium for the design, procurement and construction of the New Units.  SCE&G's share of the estimated cash outlays (future value, excluding AFC) totals approximately $6 billion for plant costs and related transmission infrastructure costs, which costs are projected based on historical one-year and five-year escalation rates as required by the SCPSC.

On March 30, 2012, the NRC approved and issued COLs for the New Units.  On April 19, 2012, SCE&G, on behalf of itself and as agent for Santee Cooper, issued a Full Notice to Proceed to the Consortium for construction of the New Units, allowing for the commencement of safety related aspects of the project.  The first New Unit is scheduled for substantial completion in March 2017, and the second New Unit is scheduled for substantial completion in May 2018.

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 structural 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. On July 11, 2012, SCE&G and the Consortium finalized an agreement which set SCE&G's portion of the costs for these specific claims at approximately $138 million (in 2007 dollars).  SCE&G anticipates that these additional costs, as well as other costs that may be identified from time to time, will be recoverable through rates.

On May 15, 2012, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost and construction schedule for the New Units. This petition replaced a February 29, 2012 petition, which was withdrawn.  The updated capital cost schedule in this petition reflects an increase of $283 million (SCE&G's portion in 2007 dollars) over the cost approved in the May 2011 order. This petition includes additional identifiable capital costs of approximately $6 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, this petition includes revised substantial completion dates for the New Units based on the March 30, 2012 issuance of the COL and costs finalized in the July 11, 2012 agreement previously discussed.  The SCPSC approved the updated construction schedule and substantially all of the capital costs in this petition on November 7, 2012.

               When the NRC issued the COLs for the New Units, it imposed two conditions on the COLs, with the first requiring inspection and testing of certain components of the New Units' passive cooling system, and the second 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 tsunami resulting from a massive earthquake, which severely damaged several nuclear generating units and their back-up cooling systems in Japan.  SCE&G is evaluating the impact these conditions and requirements impose on the construction and operation of the New Units.  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.

As previously reported, SCE&G has been advised by Santee Cooper that it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation in the New Units.  Santee Cooper has entered into letters of intent with several parties that may result in one or more of them executing a power purchase agreement or acquiring a portion of Santee Cooper's ownership interest in the New Units.  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 commercial operation dates of the New Units.  Any such project cost increase or delay could be material.

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

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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, 2011. 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.

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.

The SCPSC issued an order in January 2012 and authorized the suspension of SCE&G's natural gas hedging program. The fair value of such derivative instruments remaining to be settled were not significant for any period presented. See Note 6 of the condensed consolidated financial statements. 

ITEM 4. CONTROLS AND PROCEDURES

As of September 30, 2012, 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, 2012, 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, 2012, that has materially affected or is reasonably likely to materially affect SCE&G’s internal control over financial reporting.

60

PART II.  OTHER 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 7, 2012		James E. Swan, IV
		Controller
		(Principal accounting officer)

62

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)
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.

63

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 7, 2012
	/s/Kevin B. Marsh
	Kevin B. Marsh
	Chairman of the Board, President, Chief Executive Officer and
	Chief Operating Officer

66

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 7, 2012
	/s/Jimmy E. Addison
	Jimmy E. Addison
	Executive Vice President and Chief Financial Officer

67

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 7, 2012
	/s/Kevin B. Marsh
	Kevin B. Marsh
	Chairman of the Board and Chief Executive Officer

68

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 7, 2012
	/s/Jimmy E. Addison
	Jimmy E. Addison
	Executive Vice President and Chief Financial Officer

69

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, 2012 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 7, 2012

/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. 

70

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, 2012 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 7, 2012

/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. 

71

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, 2012 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 7, 2012

/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. 

72

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, 2012 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 7, 2012

/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. 

73

XML

DERIVATIVE FINANCIAL INSTRUMENTS (Details) (USD $)	Sep. 30, 2012		Dec. 31, 2011
Derivative [Line Items]
Derivative Cash Flow Hedge, Nonmonetary Notional Amount	30,105,750		36,427,763
Derivative not designated as hedging, notional amount	30,910,074	[1]	41,023,563	[2]
Derivative, Nonmonetary Notional Amount	61,015,824	[1]	77,451,326	[2]
Nonmonetary Notional Amount of Basis Swap, Price Risk Derivative Instruments Not Designated as Hedging Instruments	5,910,000		9,626,000
Aggregate notional amount of interest rate swaps designated as fair value hedge (in dollars)			$ 253.2
Aggregate notional amount of interest rate swaps designated as cash flow hedge (in dollars)	1.1		822.6
Gas Distribution
Derivative [Line Items]
Derivative Cash Flow Hedge, Nonmonetary Notional Amount	0		0
Derivative not designated as hedging, notional amount	8,580,000		9,080,000
Derivative, Nonmonetary Notional Amount	8,580,000		9,080,000
Retail Gas Marketing
Derivative [Line Items]
Derivative Cash Flow Hedge, Nonmonetary Notional Amount	9,650,000		6,566,000
Derivative not designated as hedging, notional amount	0		0
Derivative, Nonmonetary Notional Amount	9,650,000		6,566,000
Energy Marketing
Derivative [Line Items]
Derivative Cash Flow Hedge, Nonmonetary Notional Amount	20,455,750		29,861,763
Derivative not designated as hedging, notional amount	22,330,074	[1]	31,943,563	[2]
Derivative, Nonmonetary Notional Amount	42,785,824	[1]	61,805,326	[2]
SCE&G
Derivative [Line Items]
Aggregate notional amount of interest rate swaps designated as fair value hedge (in dollars)	971,400,000
Aggregate notional amount of interest rate swaps designated as cash flow hedge (in dollars)			$ 471,400,000
SCE&G | Gas Distribution
Derivative [Line Items]
Derivative not designated as hedging, notional amount	210,000		2,490,000

[1] (a) Includes an aggregate 5,910,000 DT related to basis swap contracts in Energy Marketing.

[2] (b) Includes an aggregate 9,626,000 DT related to basis swap contracts in Energy Marketing.

XML

SEGMENT OF BUSINESS INFORMATION (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue	$ 714	$ 728	$ 1,851	$ 1,903
Intersegment Revenue	0	0	0
Operating Income	238	215	647	605
Regulated Operating Revenue, Gas	109	115	513	613
Regulated and Unregulated Operating Revenue	1,038	1,092	3,054	3,374
Income Available to Common Shareholders of SCANA	122	105	315	289
Segment Assets	13,964		13,964		13,534
Electric Operations
Segment Reporting Information [Line Items]
Intersegment Revenue	2	2	7	6
Operating Income	243	225	534	487
Segment Assets	8,750		8,750		8,222
Gas Distribution
Segment Reporting Information [Line Items]
Intersegment Revenue	0	1		1
Operating Income	(7)	(11)	81	75
Regulated and Unregulated Operating Revenue	107	114	507	606
Segment Assets	2,208		2,208		2,179
Retail Gas Marketing
Segment Reporting Information [Line Items]
Intersegment Revenue	0	0	0
Regulated and Unregulated Operating Revenue	64	68	288	348
Income Available to Common Shareholders of SCANA	(5)	(5)	3	14
Segment Assets	121		121		185
Energy Marketing
Segment Reporting Information [Line Items]
Intersegment Revenue	35	49	84	146
Regulated and Unregulated Operating Revenue	151	180	402	510
Income Available to Common Shareholders of SCANA	1	2	5	4
Segment Assets	91		91		114
All Other [member]
Segment Reporting Information [Line Items]
Intersegment Revenue	100	102	309	308
Operating Income	6	5	17	13
Regulated and Unregulated Operating Revenue	11	10	32	30
Income Available to Common Shareholders of SCANA	(3)	(6)	(2)	(5)
Segment Assets	1,276		1,276		1,377
Adjustments/Eliminations
Segment Reporting Information [Line Items]
Intersegment Revenue	(137)	(154)	(400)	(461)
Operating Income	(4)	(4)	15	30
Regulated and Unregulated Operating Revenue	(9)	(8)	(26)	(23)
Income Available to Common Shareholders of SCANA	129	114	309	276
Segment Assets	1,518		1,518		1,457
SCE&G
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue	716	730	1,857	1,908
Regulated Operating Revenue	777	797	2,101	2,193
Operating Income	241	220	561	509
Regulated Operating Revenue, Gas	61	67	244	285
Net Income (Loss) Attributable to Parent	129	117	272	244
Segment Assets	11,630		11,630		11,037
SCE&G | Electric Operations
Segment Reporting Information [Line Items]
Operating Income	244	225	534	487
Segment Assets	8,750		8,750		8,222
SCE&G | Gas Distribution
Segment Reporting Information [Line Items]
Operating Income	(3)	(5)	27	23
Segment Assets	648		648		622
SCE&G | Adjustments/Eliminations
Segment Reporting Information [Line Items]
Operating Income	0	0		(1)
Net Income (Loss) Attributable to Parent	129	117	272	244
Segment Assets	$ 2,232		$ 2,232		$ 2,193

XML

RATE AND OTHER REGULATORY MATTERS (Details 2) (USD $)	1 Months Ended	3 Months Ended	9 Months Ended	24 Months Ended			3 Months Ended						3 Months Ended		3 Months Ended						3 Months Ended				3 Months Ended		3 Months Ended	9 Months Ended		12 Months Ended				9 Months Ended			3 Months Ended
	Nov. 30, 2010	Sep. 30, 2012	Sep. 30, 2012	Jul. 31, 2012	Dec. 31, 2011	Sep. 30, 2010	Sep. 30, 2012 Deferred Income Tax Charges [Member]	Dec. 31, 2011 Deferred Income Tax Charges [Member]	Sep. 30, 2012 Under-collections-electric fuel adjustment clause	Dec. 31, 2011 Under-collections-electric fuel adjustment clause	Sep. 30, 2012 Environmental remediation costs	Dec. 31, 2011 Environmental remediation costs	Sep. 30, 2012 Asset Retirement Obligation Costs [Member]	Dec. 31, 2011 Asset Retirement Obligation Costs [Member]	Sep. 30, 2012 Franchise agreements	Dec. 31, 2011 Franchise agreements	Sep. 30, 2012 Deferred employee benefit plan costs	Dec. 31, 2011 Deferred employee benefit plan costs	Sep. 30, 2012 Planned major maintenance	Dec. 31, 2011 Planned major maintenance	Sep. 30, 2012 Deferred losses on interest rate derivatives	Dec. 31, 2011 Deferred losses on interest rate derivatives	Sep. 30, 2012 Deferred pollution control costs	Dec. 31, 2011 Deferred pollution control costs	Sep. 30, 2012 Other.	Dec. 31, 2011 Other.	Sep. 30, 2012 SCE&G	Sep. 30, 2012 SCE&G	Sep. 30, 2011 SCE&G	Dec. 31, 2011 SCE&G	Jul. 31, 2011 SCE&G	Dec. 31, 2010 SCE&G	May 01, 2011 SCE&G	Sep. 30, 2012 SCE&G Deferred Income Tax Charges [Member]	Sep. 30, 2012 SCE&G Asset Retirement Obligation Costs [Member]	Sep. 30, 2012 SCE&G Franchise agreements	Sep. 30, 2012 SCE&G Deferred employee benefit plan costs
Regulatory Assets:
Power Generation Capacity Megawatts																											1,117	1,117
Public Utilities, Property, Plant and Equipment, Amount of Loss (Recovery) on Plant Abandonment																												$ 418,000,000
Public Utilities, Property, Plant and Equipment, Description of Plant Abandonment																												22506309
Storm Damage Reserve Cost Applied																												4,600,000	3,600,000
Public Utilities, Increase (Decrease) in Retail Natural Gas Rates Requested and Approved under RSA																												151,500,000		7.5		8.6
Public Utilities, Property, Plant and Equipment Identifiable Capital Costs	283,000,000
Capital Cost Related to New Federal Healthcare Etc.			6,000,000
Share in Approved Capital Costs						8,000,000																											173,900,000
Public Utilities Additional Labor Expenses for Oversight of New Units			132,000,000
Regulatory assets		1,290,000,000	1,290,000,000		1,279,000,000		244,000,000	243,000,000	0	28,000,000	44,000,000	30,000,000	321,000,000	316,000,000	37,000,000	40,000,000	390,000,000	392,000,000	0	6,000,000	159,000,000	154,000,000	35,000,000	25,000,000	60,000,000	45,000,000	1,216,000,000	1,216,000,000		1,206,000,000					0	0
Regulatory assets, expected recovery period (in years)		30					70						95		20						30				30									70			12
Public Utilities Base Fuel under Collected Balance Recovery Period			12																									12
MPG enviromental remediatio																												28
Environmental Remediation Costs Recognized in Regulatory Assets																											38,600,000	38,600,000
Amount Recovered Through Electric Rates to Offset Turbine Expenses				$ 18,400,000
Accrual period of nuclear refueling charges (in months)		18																									18
Public Utilities, Percent Increase (Decrease) in Retail Natural Gas Rates																														2.10%		2.10%
Public Utilities, Percent Increase (Decrease) in Retail Electric Rates																												6.61%		3.75%	4.88%
power generation capacity six coal fired units																											730	730

XML

COMMON EQUITY (Tables) (USD $)
In Millions, unless otherwise specified

9 Months Ended

Sep. 30, 2012

Sep. 30, 2011

Dec. 31, 2011

Dec. 31, 2010

Schedule of Capitalization, Equity [Line Items]

Schedule of Stockholders Equity [Table Text Block]

Changes in common equity during the nine months ended September 30, 2012 and 2011 were as follows:

Millions of dollars	2012			2011
Balance at January 1,	$	3,889		$	3,702
Common stock issued	73			73
Dividends declared	(194		)	(188		)
Comprehensive income	327			251
Balance as of September 30,	$	4,095		$	3,838

SCE&G

Schedule of Capitalization, Equity [Line Items]

Schedule of Stockholders Equity [Table Text Block]

Changes in common equity during the nine months ended September 30, 2012 and 2011 were as follows:

Millions of dollars	Common Equity			Noncontrolling Interest			Total Equity
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
Balance at January 1, 2011	$	3,437		$	104		$	3,541
Capital contribution from parent	73			—			73
Dividends declared	(146		)	(5		)	(151		)
Comprehensive income	244			7			251
Balance as of September 30, 2011	$	3,608		$	106		$	3,714

Dividends

$ (162)

$ (151)

Contributions from parent

84

73

Stockholders' Equity Attributable to Noncontrolling Interest

112

108

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

$ 3,976

$ 3,714

$ 3,773

$ 3,541

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details) (USD $)	Sep. 30, 2012	Dec. 31, 2011
Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets, Fair Value Disclosure [Abstract]
Available-for-sale Securities	$ 8,000,000	$ 3,000,000
Quoted Prices in Active Markets for Identical Assets (Level 1) | Interest Rate Contract
Assets, Fair Value Disclosure [Abstract]
Derivative Assets	0	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Commodity contracts
Assets, Fair Value Disclosure [Abstract]
Derivative Assets		0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	1,000,000
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other energy management contracts
Assets, Fair Value Disclosure [Abstract]
Derivative Assets	3,000,000	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	0
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 Assets	47,000,000	2,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	117,000,000	158,000,000
Fair Value, Inputs, Level 2 [Member] | Commodity contracts
Assets, Fair Value Disclosure [Abstract]
Derivative Assets	3,000,000	1,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	3,000,000	13,000,000
Fair Value, Inputs, Level 2 [Member] | Other energy management contracts
Assets, Fair Value Disclosure [Abstract]
Derivative Assets	15,000,000	27,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	17,000,000	26,000,000
SCE&G | Fair Value, Inputs, Level 2 [Member] | Interest Rate Contract
Assets, Fair Value Disclosure [Abstract]
Derivative Assets	47	1
Liabilities, Fair Value Disclosure [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	$ 84	$ 77

XML

LONG-TERM AND SHORT-TERM DEBT (Details 2) (USD $)																																					3 Months Ended		3 Months Ended
	Oct. 01, 2012	Sep. 30, 2012	Sep. 30, 2012 Fuel Company	Oct. 01, 2012 Wells Fargo Bank, National Association (Member)	Sep. 30, 2012 Wells Fargo Bank, National Association (Member)	Sep. 30, 2012 Bank of America, N.A. (Member)	Sep. 30, 2012 Morgan Stanly Bank, N.A. (Member)	Sep. 30, 2012 Branch Banking and Trust Company (Member)	Sep. 30, 2012 Credit Suisse AG, Cayman Islands Branch (Member)	Sep. 30, 2012 JPMorgan Chase Bank, N.A. (Member)	Sep. 30, 2012 Mizuho Corporate Bank, Ltd (Member)	Sep. 30, 2012 TD Bank, N.A. (Member)	Sep. 30, 2012 UBS Loan Finance LLC (Member)	Sep. 30, 2012 Deutsche Bank AG, New York Branch (Member)	Sep. 30, 2012 Union Bank, N.A. (Member)	Sep. 30, 2012 US Bank National Association (Member)	Oct. 01, 2012 SCE&G	Sep. 30, 2012 SCE&G	Dec. 31, 2011 SCE&G	Sep. 30, 2012 Parent Company [Member]	Dec. 31, 2011 Parent Company [Member]	Sep. 30, 2012 Retail Gas Marketing and Energy Marketing	Dec. 31, 2011 Retail Gas Marketing and Energy Marketing	Oct. 01, 2012 SCE&G (including Fuel Company)	Sep. 30, 2012 SCE&G (including Fuel Company)	Dec. 31, 2011 SCE&G (including Fuel Company)	Sep. 30, 2012 SCE&G (including Fuel Company) Wells Fargo Bank, National Association (Member)	Oct. 01, 2012 SCE and G [Member]	Sep. 30, 2012 SCE and G [Member]	Oct. 01, 2012 SCE and G [Member] Deutsche Bank AG, New York Branch (Member)	Sep. 30, 2012 SCE and G [Member] Deutsche Bank AG, New York Branch (Member)	Sep. 30, 2012 SCE and G [Member] Three other banks (Member)	Oct. 01, 2012 Fuel Company	Sep. 30, 2012 Fuel Company	Sep. 30, 2012 PSNC Energy	Dec. 31, 2011 PSNC Energy	Sep. 30, 2012 First Mortgage Bonds [Member]	Sep. 30, 2012 First Mortgage Bonds [Member] SCE&G	Sep. 30, 2012 Medium Term Notes First [Member]	Sep. 30, 2012 Medium Term Notes First [Member] SCE and G [Member]	Sep. 30, 2012 Medium-term Notes [Member]
Debt Instrument [Line Items]
Due to Affiliate, Current																		$ 109,000,000	$ 136,000,000			$ 10,100,000	$ 13,200,000
Debt Instruments [Abstract]
Debt Instrument, Increase, Additional Borrowings																																					250,000,000		250,000,000	250,000,000
Debt Instrument, Interest Rate, Stated Percentage																																						4.35%	4.125%		6.25%
Face value of Industrial Revenue Bonds issued, proceeds of which were availed as loan																													67,800,000
Lines of credit:
Line of Credit Facility, Maximum Borrowing Capacity	1,800,000,000	1,500,000,000	500,000,000																	300,000,000	300,000,000			200,000,000	1,100,000,000	1,100,000,000		1,400,000,000					500,000,000	400,000,000	100,000,000	100,000,000
Commercial Paper																				66,000,000	131,000,000				327,000,000	512,000,000									0	10,000,000
Commercial paper, weighted average interest rate (as a percent)																				0.80%	0.63%				0.47%	0.56%									0.00%	0.57%
Letters of credit supported by LOC																				3,000,000	3,000,000				0	0									0	0
Line of Credit Facility, Remaining Borrowing Capacity																				231,000,000	166,000,000				773,000,000	588,000,000									100,000,000	90,000,000
LOC advances																				$ 0	$ 0				$ 0	$ 0									$ 0	$ 0
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank				10.70%	10.00%	10.00%	10.00%	8.00%	8.00%	8.00%	8.00%	8.00%	8.00%	5.30%	5.30%	5.30%											10.00%			6.30%	5.30%	6.00%
Number of other banks (in entities)		3															2

XML

AFFILIATED TRANSACTIONS - SCEG AFFILIATED TRANSACTIONS -SCEG (Details) (USD $) In Millions, unless otherwise specified				9 Months Ended	12 Months Ended		9 Months Ended
	Sep. 30, 2012	Dec. 31, 2011	Sep. 30, 2012 Canadys Refined Coal LLC [Member]	Sep. 30, 2012 Cope Refined Coal LLC [Member]	Dec. 31, 2011 Cope Refined Coal LLC [Member]	Sep. 30, 2011 Cope Refined Coal LLC [Member]	Sep. 30, 2012 CGT [Member]	Sep. 30, 2011 CGT [Member]	Sep. 30, 2012 Retail Gas Marketing and Energy Marketing	Sep. 30, 2011 Retail Gas Marketing and Energy Marketing	Dec. 31, 2011 Retail Gas Marketing and Energy Marketing
Related Party Transaction [Line Items]
Related Party Transaction Purchases from Related Party				$ 87.3	$ 100.9		$ 27.1	$ 22.8
Due to Affiliate, Current							2.8	2.5	10.1		13.2
Equity Method Investment, Ownership Percentage			40.00%	10.00%
Increase (Decrease) Due from Affiliates				10.8	8.5
Cost of Natural Gas Purchases									84.0	146.6
Equity Method Investment, Dividends or Distributions				10.8	8.6
Energy Related Inventory, Coal				86.9		100.5
Related Party Transaction, Due from (to) Related Party, Current	49.3	58.5
Accounts Payable, Related Parties, Current	$ 45	$ 43

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parentheticals) (USD $)	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Cash paid for interest, capitalized interest	$ 8	$ 7
SCE&G
Cash paid for interest, capitalized interest	$ 7	$ 6

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details 2) (USD $) In Millions, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Carrying Amount
Financial instruments for which the carrying amount may not equal estimated fair value
Long-term debt	$ 5,153.0	$ 4,653.0
Estimated Fair Value
Financial instruments for which the carrying amount may not equal estimated fair value
Long-term debt	6,241.6	5,479.2
SCE&G | Carrying Amount
Financial instruments for which the carrying amount may not equal estimated fair value
Long-term debt	3,753.6	3,241.5
SCE&G | Estimated Fair Value
Financial instruments for which the carrying amount may not equal estimated fair value
Long-term debt	$ 4,661.0	$ 3,920.3

XML

EMPLOYEE BENEFIT PLANS (Tables)

9 Months Ended

Sep. 30, 2012

Pension and Other Postretirement Benefit Plans

Schedule of Net Benefit Costs [Table Text Block]

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

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2012			2011			2012		2011
Three months ended September 30,
Service cost	$	5.0		$	4.5		$	1.1	$	1.0
Interest cost	10.9			10.4			2.9		3.2
Expected return on assets	(15.0		)	(15.3		)	—		—
Prior service cost amortization	1.8			1.7			0.2		0.2
Transition obligation amortization	—			—			0.2		0.1
Amortization of actuarial loss	4.5			3.1			—		0.1
Net periodic benefit cost	$	7.2		$	4.4		$	4.4	$	4.6
Nine months ended September 30,
Service cost	$	14.7		$	13.7		$	3.6	$	3.2
Interest cost	32.2			32.6			8.9		9.2
Expected return on assets	(44.6		)	(47.7		)	—		—
Prior service cost amortization	5.3			5.3			0.7		0.8
Transition obligation amortization	—			—			0.5		0.5
Amortization of actuarial loss	13.8			9.1			0.4		0.3
Net periodic benefit cost	$	21.4		$	13.0		$	14.1	$	14.0

SCE&G

Pension and Other Postretirement Benefit Plans

Schedule of Net Benefit Costs [Table Text Block]

urance 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	2012			2011			2012		2011
Three months ended September 30,
Service cost	$	4.1		$	3.6		$	0.8	$	0.7
Interest cost	9.1			8.8			2.3		2.5
Expected return on assets	(12.6		)	(13.0		)	—		—
Prior service cost amortization	1.6			1.5			0.1		0.2
Amortization of actuarial loss	3.7			2.6			0.1		0.1
Net periodic benefit cost	$	5.9		$	3.5		$	3.3	$	3.5
Nine months ended September 30,
Service cost	$	11.8		$	11.0		$	2.8	$	2.5
Interest cost	27.3			27.7			7.0		7.2
Expected return on assets	(37.8		)	(40.5		)	—		—
Prior service cost amortization	4.5			4.5			0.5		0.6
Amortization of actuarial loss	11.7			7.7			0.3		0.2
Net periodic benefit cost	$	17.5		$	10.4		$	10.6	$	10.5

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Tables)

9 Months Ended

Sep. 30, 2012

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

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

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		Significant Other
		Markets for Identical Assets		Observable Inputs
Millions of dollars		(Level 1)		(Level 2)
As of September 30, 2012
Assets -	Available for sale securities	$	8	—
	Interest rate contracts	—		$	47
	Commodity contracts	3		3
	Energy management contracts	—		15
Liabilities -	Interest rate contracts	—		117
	Commodity contracts	—		3
	Energy management contracts	—		17
As of December 31, 2011
Assets -	Available for sale securities	$	3	—
	Interest rate contracts	—		$	2
	Commodity contracts	—		1
	Energy management contracts	—		27
Liabilities -	Interest rate contracts	—		158
	Commodity contracts	1		13
	Energy management contracts	—		26

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, 2012 and December 31, 2011 were as follows:

	September 30, 2012				December 31, 2011
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	5,153.0	$	6,241.6	$	4,653.0	$	5,479.2

SCE&G

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

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

Consolidated SCE&G’s interest rate swap agreements are valued using discounted cashflow models with independently sourced market 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, 2012	December 31, 2011
Assets -	Interest rate contracts	$47	$1
Liabilities -	Interest rate contracts	84	77

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, 2012 and December 31, 2011 were as follows:

	September 30, 2012				December 31, 2011
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	3,753.6	$	4,661.0	$	3,241.5	$	3,920.3

XML

EMPLOYEE BENEFIT PLANS (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Components of Net Periodic Benefit Cost
Pension Costs Related to Retail Electric Operations and Natural Gas Operations Deferred as Regulatory Assets	$ 4,000,000	$ 2,200,000	$ 11,400,000	$ 6,800,000
Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	5,000,000	4,500,000	14,700,000	13,700,000
Interest cost	10,900,000	10,400,000	32,200,000	32,600,000
Expected return on assets	(15,000,000)	(15,300,000)	(44,600,000)	(47,700,000)
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	1,800,000	1,700,000	5,300,000	5,300,000
Defined Benefit Plan, Amortization of Transition Obligations (Assets)	0	0	0	0
Defined Benefit Plan, Actuarial Net (Gains) Losses	4,500,000	3,100,000	13,800,000	9,100,000
Defined Benefit Plan, Net Periodic Benefit Cost	7,200,000	4,400,000	21,400,000	13,000,000
Other Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	1,100,000	1,000,000	3,600,000	3,200,000
Interest cost	2,900,000	3,200,000	8,900,000	9,200,000
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	200,000	200,000	700,000	800,000
Defined Benefit Plan, Amortization of Transition Obligations (Assets)	200,000	100,000	500,000	500,000
Defined Benefit Plan, Actuarial Net (Gains) Losses	0	100,000	400,000	300,000
Defined Benefit Plan, Net Periodic Benefit Cost	4,400,000	4,600,000	14,100,000	14,000,000
SCE&G
Pension and Other Postretirement Benefit Plans
Environmental Remediation Costs Recognized in Regulatory Assets	38,600,000		38,600,000
Components of Net Periodic Benefit Cost
Pension Costs Related to Retail Electric Operations and Natural Gas Operations Deferred as Regulatory Assets	4,000,000	2,200,000	11,400,000	6,800,000
SCE&G | Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	4,100,000	3,600,000	11,800,000.00	11,000,000.00
Interest cost	9,100,000.00	8,800,000.00	27,300,000.00	27,700,000.00
Expected return on assets	12,600,000	13,000,000	37,800,000	40,500,000
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	1,600,000.00	1,500,000.00	4,500,000	4,500,000
Defined Benefit Plan, Actuarial Net (Gains) Losses	3,700,000.00	2,600,000.00	11,700,000	7,700,000
SCE&G | Other Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	800,000	700,000	2,800,000.00	2,500,000
Interest cost	2,300,000.00	2,500,000.00	7,000,000.00	7,200,000.00
Expected return on assets	0.0	0.0	0	0.0
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	100,000.00	200,000.00	500,000	600,000
Defined Benefit Plan, Actuarial Net (Gains) Losses	$ 100,000.00	$ 100,000.00	$ 300,000	$ 200,000

XML

SEGMENT OF BUSINESS INFORMATION (Tables)

9 Months Ended

Sep. 30, 2012

Segment Reporting Information [Line Items]

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

industries.

	External			Intersegment			Operating			Net
Millions of dollars	Revenue			Revenue			Income			Income
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
Three Months Ended September 30, 2011
Electric Operations	$	728		$	2		$	225		n/a
Gas Distribution	114			1			(11		)	n/a
Retail Gas Marketing	68			—			n/a			$	(5	)
Energy Marketing	180			49			n/a			2
All Other	10			102			5			(6		)
Adjustments/Eliminations	(8		)	(154		)	(4		)	114
Consolidated Total	$	1,092		$	—		$	215		$	105

Nine months Ended September 30, 2011
Electric Operations	$	1,903		$	6		$	487	n/a
Gas Distribution	606			1			75		n/a
Retail Gas Marketing	348			—			n/a		$	14
Energy Marketing	510			146			n/a		4
All Other	30			308			13		(5		)
Adjustments/Eliminations	(23		)	(461		)	30		276
Consolidated Total	$	3,374		$	—		$	605	$	289

	September 30,		December 31,
Segment Assets	2012		2011
Electric Operations	$	8,750	$	8,222
Gas Distribution	2,208		2,179
Retail Gas Marketing	121		185
Energy Marketing	91		114
All Other	1,276		1,377
Adjustments/Eliminations	1,518		1,457
Consolidated Total	$	13,964	$	13,534

SCE&G

Segment Reporting Information [Line Items]

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

allocated to the Electric Operations and Gas Distribution segments.  Intersegment revenues were not significant.

			Operating			Earnings Available
	External		Income			To Common
Millions of dollars	Revenue		(Loss)			Shareholder
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

Three Months Ended September 30, 2011
Electric Operations	$	730	$	225		n/a
Gas Distribution	67		(5		)	n/a
Adjustments/Eliminations	—		—			$	117
Consolidated Total	$	797	$	220		$	117
Nine Months Ended September 30, 2011
Electric Operations	$	1,908	$	487		n/a
Gas Distribution	285		23			n/a
Adjustments/Eliminations	—		(1		)	$	244
Consolidated Total	$	2,193	$	509		$	244

	September 30,		December 31,
Segment Assets	2012		2011
Electric Operations	$	8,750	$	8,222
Gas Distribution	648		622
Adjustments/Eliminations	2,232		2,193
Consolidated Total	$	11,630	$	11,037

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011
Asset Management and Supply Service Agreements
Percentage of natural gas inventory held by counterparties under asset management and supply service agreements (as a percent)	48.00%		48.00%		45.00%
Natural gas inventory, carrying amount	$ 20.4		$ 20.4		$ 28.7
Property, Plant and Equipment, Net	307		307		305
Earnings Per Share
Weighted Average Shares Outstanding - Basic	131,400,000	129,100,000	130,800,000	128,500,000
Incremental Common Shares Attributable to Share-based Payment Arrangements and Equity Forward Agreements	2,400,000	1,200,000	2,300,000	1,300,000
Weighted Average Number of Shares Outstanding, Diluted	133,800,000	130,300,000	133,100,000	129,800,000
SCE&G
Significant Accounting Policies
Power Generation Capacity Megawatts	1,117		1,117
Asset Management and Supply Service Agreements
Property, Plant and Equipment, Net	58		58		52
Genco
Significant Accounting Policies
Power Generation Capacity Megawatts	605		605
Asset Management and Supply Service Agreements
Property, Plant and Equipment, Net	$ 480		$ 480

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Cash Flows From Operating Activities:
Income Available to Common Shareholders of SCANA	$ 315	$ 289
Adjustments to reconcile net income to net cash provided from operating activities:
Earnings from equity method investments, net of distributions	(1)	1
Deferred income taxes, net	74	97
Depreciation and amortization	277	263
Amortization of nuclear fuel	38	27
Allowance for equity funds used during construction	(13)	(13)
Cash provided (used) by changes in certain assets and liabilities:
Receivables	46	175
Inventories	(34)	2
Prepayments and other	58	68
Regulatory liabilities	47	(12)
Accounts payable	(7)	(108)
Taxes accrued	(21)	(21)
Interest accrued	4	(1)
Regulatory assets	(2)	(88)
Changes in other assets	5	(10)
Changes in other liabilities	(18)	8
Net Cash Provided From Operating Activities	768	677
Cash Flows From Investing Activities:
Property additions and construction expenditures	(868)	(715)
Proceeds from investments (including derivative collateral posted)	364	16
Purchase of investments (including derivative collateral posted)	(326)	(116)
Payments for (Proceeds from) Hedge, Investing Activities	14	0
Payments for interest rate contract settlements	(51)	(61)
Net Cash Used in Investing Activities	(867)	(876)
Cash Flows From Financing Activities:
Proceeds from Issuance of Common Stock	73	73
Proceeds from issuance of long-term debt	763	796
Repayments of Long-term Debt	(274)	(627)
Dividends	(192)	(185)
Short-term borrowings, net	(259)	161
Net Cash Provided From Financing Activities	111	218
Net (Decrease) Increase in Cash and Cash Equivalents	12	19
Cash and Cash Equivalents, January 1	29	55
Cash and Cash Equivalents, September 30	41	74
Supplemental Cash Flow Information:
Cash paid for-Interest (net of capitalized interest )	212	206
Cash paid for-Income taxes	67	0
Noncash Investing and Financing Activities:
Accrued construction expenditures	79	62
Capital Lease Obligations Incurred	4	2
SCE&G
Cash Flows From Operating Activities:
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	281	251
Adjustments to reconcile net income to net cash provided from operating activities:
Losses from equity method investments	3	2
Deferred income taxes, net	74	83
Depreciation and amortization	221	214
Amortization of nuclear fuel	38	27
Allowance for equity funds used during construction	(12)	(12)
Cash provided (used) by changes in certain assets and liabilities:
Receivables	(22)	11
Inventories	(49)	20
Prepayments and other	(57)	63
Regulatory liabilities	49	(10)
Accounts payable	13	(40)
Taxes accrued	(8)	(14)
Interest accrued	(1)	(1)
Regulatory assets	(1)	(90)
Changes in other assets	44	(7)
Changes in other liabilities	(20)	6
Net Cash Provided From Operating Activities	553	503
Cash Flows From Investing Activities:
Property additions and construction expenditures	(793)	(641)
Proceeds from investments (including derivative collateral posted)	196	5
Purchase of investments (including derivative collateral posted)	(199)	(37)
Payments for (Proceeds from) Hedge, Investing Activities	14	0
Payments for interest rate contract settlements	0	(31)
Net Cash Used in Investing Activities	(782)	(704)
Cash Flows From Financing Activities:
Proceeds from issuance of long-term debt	517	349
Repayments of Long-term Debt	(13)	(166)
Dividends	(146)	(155)
Contributions from parent	84	73
Short-term borrowings, net	(185)	116
Short-term borrowings- affiliate,net	(9)	(30)
Net Cash Provided From Financing Activities	248	187
Net (Decrease) Increase in Cash and Cash Equivalents	19	(14)
Cash and Cash Equivalents, January 1	16	31
Cash and Cash Equivalents, September 30	35	17
Supplemental Cash Flow Information:
Cash paid for-Interest (net of capitalized interest )	147	138
Cash paid for-Income taxes	81	0
Noncash Investing and Financing Activities:
Accrued construction expenditures	66	56
Capital Lease Obligations Incurred	$ 4	$ 2

XML

RATE AND OTHER REGULATORY MATTERS (Details) (USD $)	1 Months Ended	3 Months Ended	9 Months Ended	12 Months Ended	3 Months Ended		9 Months Ended	12 Months Ended			24 Months Ended
	Nov. 30, 2010	Sep. 30, 2012	Sep. 30, 2012	Dec. 31, 2011	Sep. 30, 2012 SCE&G	Sep. 30, 2011 SCE&G	Sep. 30, 2012 SCE&G	Dec. 31, 2011 SCE&G	Jul. 31, 2011 SCE&G	Dec. 31, 2010 SCE&G	Jul. 31, 2012 SCE&G	May 01, 2012 SCE&G
Rate Matters [Line Items]
Public Utilities, Property, Plant and Equipment, Amount of Loss (Recovery) on Plant Abandonment							$ 418,000,000
Public Utilities, Property, Plant and Equipment, Description of Plant Abandonment							22506309
Amount Recovered Through Electric Rates to Offset Deferred Pollution, Control Costs					9,100,000		9,100,000
Public Utilities, Percent Increase (Decrease) in Retail Electric Rates							6.61%	3.75%	4.88%
Allowable return on common equity (as a percent)						11.00%					10.70%
Length of credit period (in years)											two
Demand Side Management Program Costs, Noncurrent												19,600,000
Public Utilities Stipulations Related to Rate Matters Credit Offset by Amortization of Weather Related Revenues Benenefits Exhausted									48,700,000
Public Utilities Construction of New Nuclear Generating Units							6
Public Utilities, Property, Plant and Equipment Identifiable Capital Costs	283,000,000
Public Utilities Additional Labor Expenses for Oversight of New Units			132,000,000
Public Utilities Percent Increase (Decrease) in Retail Electric Rates Requested and Approved Under BLRA								2.30%		2.40%
Increase (decrease) in retail electric rate requested under the BLRA								52.1		52.8
Public Utilities, Percent Increase (Decrease) in Retail Natural Gas Rates								2.10%		2.10%
Public Utilities, Increase (Decrease) in Retail Natural Gas Rates Requested and Approved under RSA							$ 151,500,000	$ 7.5		$ 8.6
Basis for rate calculation				12	12-month rolling average
Public Utilities, Increase (Decrease) in Cost of Gas Component of Retail Natural Gas Rates		0
Regulatory Noncurrent Asset, Amortization Period		30

XML

DERIVATIVE FINANCIAL INSTRUMENTS (Details 2) (USD $) In Millions, unless otherwise specified	Sep. 30, 2012		Dec. 31, 2011
Derivatives designated as hedging instruments
Derivative [Line Items]
Asset Derivatives Fair Value	$ 51		$ 3
Liability Derivatives Fair Value	120		172
Derivatives not designated as hedging instruments
Derivative [Line Items]
Asset Derivatives Fair Value	17		27
Liability Derivatives Fair Value	15		25
Interest Rate Contract | Derivatives designated as hedging instruments | Prepayments and other
Derivative [Line Items]
Asset Derivatives Fair Value	27		2
Interest Rate Contract | Derivatives designated as hedging instruments | Other deferred debits and other assets
Derivative [Line Items]
Asset Derivatives Fair Value	20
Interest Rate Contract | Derivatives designated as hedging instruments | Other current liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	75		55
Interest Rate Contract | Derivatives designated as hedging instruments | Other deferred credits and other liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	42		103
Commodity contracts | Derivatives designated as hedging instruments | Prepayments and other
Derivative [Line Items]
Asset Derivatives Fair Value	2
Liability Derivatives Fair Value	3		1	[1]
Commodity contracts | Derivatives designated as hedging instruments | Other current liabilities
Derivative [Line Items]
Asset Derivatives Fair Value	2	[1]	1	[1]
Liability Derivatives Fair Value			10
Commodity contracts | Derivatives designated as hedging instruments | Other deferred credits and other liabilities
Derivative [Line Items]
Liability Derivatives Fair Value			3
Commodity contracts | Derivatives not designated as hedging instruments | Prepayments and other
Derivative [Line Items]
Asset Derivatives Fair Value	2
Other Energy Management Contract [Member] | Derivatives not designated as hedging instruments | Prepayments and other
Derivative [Line Items]
Asset Derivatives Fair Value	8		17
Liability Derivatives Fair Value	1	[1]	3	[1]
Other Energy Management Contract [Member] | Derivatives not designated as hedging instruments | Other deferred debits and other assets
Derivative [Line Items]
Asset Derivatives Fair Value	7		10
Other Energy Management Contract [Member] | Derivatives not designated as hedging instruments | Other current liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	7		13
Other Energy Management Contract [Member] | Derivatives not designated as hedging instruments | Other deferred credits and other liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	7		9
SCE&G | Derivatives designated as hedging instruments
Derivative [Line Items]
Asset Derivatives Fair Value	47		1
Liability Derivatives Fair Value	84		77
SCE&G | Interest Rate Contract | Derivatives designated as hedging instruments | Prepayments and other
Derivative [Line Items]
Asset Derivatives Fair Value	27		1
SCE&G | Interest Rate Contract | Derivatives designated as hedging instruments | Other deferred debits and other assets
Derivative [Line Items]
Asset Derivatives Fair Value	20
SCE&G | Interest Rate Contract | Derivatives designated as hedging instruments | Other current liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	72		2
SCE&G | Interest Rate Contract | Derivatives designated as hedging instruments | Other deferred credits and other liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	$ 12		$ 75

[1] (c) Asset derivatives represent unrealized gains to the Company, and liability derivatives represent unrealized losses. In the Company’s condensed consolidated balance sheets, unrealized gain and loss positions on commodity contracts with the same counterparty are reported as either a net asset or liability, and for purposes of the above disclosure they are reported on a gross basis.

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CONSOLIDATED BALANCE SHEETS (USD $) In Millions, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Assets
Utility Plant In Service	$ 11,631	$ 12,000
Accumulated Depreciation and Amortization	(3,790)	(3,836)
Construction Work in Progress	1,945	1,482
Plant to be Retired, Net	418	0
Nuclear Fuel, Net of Accumulated Amortization	163	171
Goodwill, Net of Writedown of $230	230	230
Utility Plant, Net	10,597	10,047
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	307	305
Assets held in trust, net-nuclear decommissioning	94	84
Other investments	87	87
Nonutility Property and Investments, Net	488	476
Current Assets:
Cash and cash equivalents	41	29
Receivables, net of allowance for uncollectible accounts	694	756
Inventories (at average cost):
Fuel	304	313
Materials and supplies	134	129
Emission allowances	2	2
Prepayments and other	177	236
Deferred income taxes	9	26
Total Current Assets	1,361	1,491
Deferred Debits and Other Assets:
Regulatory assets	1,290.0	1,279.0
Other	228	241
Total Deferred Debits and Other Assets	1,518	1,520
Total	13,964	13,534
Capitalization and Liabilities
Common equity	4,095	3,889
Long-Term Debt, Net	4,976	4,622
Total Capitalization	9,071	8,511
Current Liabilities:
Short-term borrowings	394	653
Current portion of long-term debt	176	31
Accounts payable	297	374
Customer deposits and customer prepayments	103	103
Taxes accrued	133	154
Interest accrued	78	74
Dividends declared	65	63
Derivative financial instruments	81	77
Other	84	113
Total Current Liabilities	1,411	1,642
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,598	1,533
Deferred investment tax credits	37	40
Asset retirement obligations	500	474
Pension and other postretirement benefits	299	291
Regulatory liabilities	863	778
Other	185	265
Total Deferred Credits and Other Liabilities	3,482	3,381
Commitments and Contingencies (Note 9)	0	0
Total	13,964	13,534
SCE&G
Assets
Utility Plant In Service	9,904	10,312
Accumulated Depreciation and Amortization	(3,304)	(3,367)
Construction Work in Progress	1,908	1,472
Plant to be Retired, Net	418	0
Nuclear Fuel, Net of Accumulated Amortization	163	171
Utility Plant, Net	9,089	8,588
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	58	52
Assets held in trust, net-nuclear decommissioning	94	84
Other investments	3	2
Nonutility Property and Investments, Net	155	138
Current Assets:
Cash and cash equivalents	35	16
Receivables, net of allowance for uncollectible accounts	486	482
Due from Affiliate, Current	11	9
Inventories (at average cost):
Fuel	204	196
Materials and supplies	124	120
Emission allowances	2	2
Prepayments and other	139	82
Deferred income taxes	0	8
Total Current Assets	1,001	915
Deferred Debits and Other Assets:
Regulatory assets	1,216.0	1,206.0
Other	169	190
Total Deferred Debits and Other Assets	1,385	1,396
Total	11,630	11,037
Capitalization and Liabilities
Common equity	3,864	3,665
Stockholders' Equity Attributable to Noncontrolling Interest	112	108
Long-Term Debt, Net	3,585	3,222
Total Capitalization	7,561	6,995
Current Liabilities:
Short-term borrowings	327	512
Current portion of long-term debt	169	19
Accounts payable	188	231
Due to Affiliate, Current	109.0	136.0
Customer deposits and customer prepayments	50	54
Taxes accrued	142	150
Interest accrued	53	54
Dividends declared	55	39
Derivative financial instruments	72	2
Other	35	61
Total Current Liabilities	1,200	1,258
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,437	1,371
Deferred investment tax credits	37	40
Asset retirement obligations	476	449
Pension and other postretirement benefits	183	179
Regulatory liabilities	649	575
Other	87	170
Total Deferred Credits and Other Liabilities	2,869	2,784
Commitments and Contingencies (Note 9)	0	0
Total	$ 11,630	$ 11,037

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COMMITMENTS AND CONTINGENCIES (Details) (USD $)	1 Months Ended	3 Months Ended	9 Months Ended				3 Months Ended	9 Months Ended	12 Months Ended			3 Months Ended
	Nov. 30, 2010	Sep. 30, 2012	Sep. 30, 2012	Jul. 11, 2012	Dec. 31, 2011	Sep. 30, 2010	Sep. 30, 2012 SCE&G	Sep. 30, 2012 SCE&G	Dec. 31, 2011 SCE&G	Dec. 31, 2005 SCE&G	May 01, 2011 SCE&G	Sep. 30, 2012 PSNC Energy	Sep. 30, 2012 SCE&G
Nuclear Insurance
Federal limit on public liability claims from nuclear incident, approximate							$ 12,600,000,000
scg_Maximum Insurance Coverage for each Nuclear Plant by ANI							375,000,000	375,000,000
Maximum liability assessment per reactor for each nuclear incident							117,500,000		78,300,000
Maximum yearly assessment per reactor							17,500,000						11,700,000
Inflation adjustment period for nuclear insurance			5
Maximum prosepective insurance premium per nuclear incident							37,300,000
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
Environmental
Number of states required to reduce emissions to attain mandated levels										28
Years to meet standards CAMR								4
Public Utilities Construction of New Nuclear Generating Units								6
Number of MGP decommissioned sites that contain residues of by-product chemicals							4
Additional costs to be incurred for remediation							22,400,000
Deferred costs, net of costs previously recovered through rates and insurance settlements included in regulatory assets							38,600,000	38,600,000
Number of MGP sites that require environmental clean-up												5
Regulatory assets		1,290,000,000	1,290,000,000		1,279,000,000		1,216,000,000	1,216,000,000	1,206,000,000			3,100,000
Nuclear Generation
Number of nuclear electric generation units								2
Power Generation Capacity Megawatts							1,117	1,117
Percentage applicable to the Company (as a percent)		55.00%	55.00%		55.00%		55.00%	55.00%	55.00%
Percentage applicable to joint owner 2 (as a percent)		45.00%	45.00%				45.00%	45.00%
Estimated cash outflow for plant costs and related transmission infrastructure costs of nuclear electric generation site		6,000,000,000
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress				138,000,000
Capital Cost Related to New Federal Healthcare Etc.			6,000,000
Public Utilities, Property, Plant and Equipment Identifiable Capital Costs	283,000,000
Share in Approved Capital Costs						8,000,000					173,900,000
Public Utilities Additional Labor Expenses for Oversight of New Units			$ 132,000,000

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012		Sep. 30, 2011
Net Income (Loss) Attributable to Parent [Abstract]
Income Available to Common Shareholders	$ 122	$ 105	$ 315		$ 289
Other Comprehensive Income (Loss)
Unrealized gains (losses) on cash flow hedging activities arising during period	1	(33)	(6)		(46)
Losses on cash flow hedging activities reclassified to net income	3	2	17		8
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax	0	0	1		0
Other Comprehensive Income	4	(31)	12		(38)
Total Comprehensive Income (Loss)	126	74	327	[1]	251	[1]
SCE&G
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	132	119	281		251
Other Comprehensive Income (Loss)
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax	0	0	0		0
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	132	119	281		251
Total Comprehensive Income (Loss)			281		251
Genco
Other Comprehensive Income (Loss)
Less comprehensive income attributable to noncontrolling interest	(3)	(2)	(9)		(7)
Total Comprehensive Income (Loss)			9		7
SCE&G (including Fuel Company)
Other Comprehensive Income (Loss)
Total Comprehensive Income (Loss)	$ 129	$ 117	$ 272		$ 244

[1] (1) Accumulated other comprehensive loss totaled $81.8 million as of September 30, 2012 and $93.8 million as of December 31, 2011.

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COMMON EQUITY (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012		Sep. 30, 2011		Dec. 31, 2011	Dec. 31, 2010	Sep. 30, 2010
Schedule of Capitalization, Equity [Line Items]
Common Stock, Shares Authorized	200		200				200
COMMON EQUITY [Abstract]
Common Shareholders' Equity	$ 4,095		$ 4,095				$ 3,889
Forward Contract Indexed to Issuer's Equity, Indexed Shares									6.6
Dividends declared			(194)		(188)
Total Comprehensive Income (Loss)	126	74	327	[1]	251	[1]
Common Stock, Shares, Outstanding	131.5		131.5				129.9
Losses on cash flow hedging activities reclassified to net income	3	2	17		8
Common stock issued			73		73
Common Stockholders' Equity		3,838			3,838			3,702
SCE&G
Schedule of Capitalization, Equity [Line Items]
Common Stock, Shares Authorized	50		50				50
COMMON EQUITY [Abstract]
Stockholders' Equity Attributable to Noncontrolling Interest	112		112				108
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	3,976	3,714	3,976		3,714		3,773	3,541
Contributions from parent			84		73
Dividends			(162)		(151)
Total Comprehensive Income (Loss)			281		251
Common Stock, Shares, Outstanding	40.3		40.3
SCE&G (including Fuel Company)
COMMON EQUITY [Abstract]
Contributions from parent			84		73
Dividends			(157)		(146)
Common Shareholders' Equity	3,864	3,608	3,864		3,608		3,665	3,437
Total Comprehensive Income (Loss)	129	117	272		244
Genco
COMMON EQUITY [Abstract]
Stockholders' Equity Attributable to Noncontrolling Interest	112	106	112		106		108	104
Contributions from parent			0		0
Dividends			(5)		(5)
Total Comprehensive Income (Loss)			$ 9		$ 7

[1] (1) Accumulated other comprehensive loss totaled $81.8 million as of September 30, 2012 and $93.8 million as of December 31, 2011.

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INCOME TAXES Income Taxes (Policies)

9 Months Ended

Sep. 30, 2012

Income Taxes [Abstract]

Income Tax, Policy [Policy Text Block]

The Company recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses. I

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LONG-TERM AND SHORT-TERM DEBT (Details) (USD $)	Oct. 01, 2012	Sep. 30, 2012	Dec. 31, 2011
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 1,800,000,000	$ 1,500,000,000
Long-term Debt, Current Maturities		176,000,000	31,000,000
Long- Term Debt Noncurrent including Derivative Liabilities		4,976,000,000	4,622,000,000
SCE&G (including Fuel Company)
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	200,000,000	1,100,000,000	1,100,000,000
Commercial Paper		327,000,000	512,000,000
Debt, Weighted Average Interest Rate		0.47%	0.56%
Letters of Credit Outstanding, Amount		0	0
Line of Credit Facility, Remaining Borrowing Capacity		773,000,000	588,000,000
SCE&G
Debt Instrument [Line Items]
Long-term Debt, Current Maturities		169,000,000	19,000,000
Long- Term Debt Noncurrent including Derivative Liabilities		3,585,000,000	3,222,000,000
Fuel Company
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 500,000,000	$ 400,000,000
First Mortgage Bonds [Member] | SCE&G
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.35%

XML

RATE AND OTHER REGULATORY MATTERS (Tables)

9 Months Ended

Sep. 30, 2012

Regulatory Assets:

Schedule of Regulatory Assets [Table Text Block]

Millions of dollars	September 30, 2012		December 31, 2011
Regulatory Assets:
Accumulated deferred income taxes	$	244	$	243
Under-collections - electric fuel adjustment clause	—		28
Environmental remediation costs	44		30
AROs and related funding	321		316
Franchise agreements	37		40
Deferred employee benefit plan costs	390		392
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	159		154
Deferred pollution control costs	35		25
Other	60		45
Total Regulatory Assets	$	1,290	$	1,279

Schedule of Regulatory Liabilities [Table Text Block]

Regulatory Liabilities:
Accumulated deferred income taxes	$	21	$	23
Asset removal costs	688		662
Storm damage reserve	27		32
Monetization of bankruptcy claim	32		34
Deferred gains on interest rate derivatives	85		26
Planned major maintenance	8		—
Other	2		1
Total Regulatory Liabilities	$	863	$	778

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

Year	Increase	Amount (Millions)
2012	2.3%	$52.1
2011	2.4%	$52.8

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

Year	Action			Amount (Millions)
2012	2.1	%	Increase	$7.5
2011	2.1	%	Increase	$8.6

SCE&G

Regulatory Assets:

Schedule of Regulatory Assets [Table Text Block]

Millions of dollars	September 30, 2012		December 31, 2011
Regulatory Assets:
Accumulated deferred income taxes	$	238	$	238
Under collections – electric fuel adjustment clause	—		28
Environmental remediation costs	39		25
AROs and related funding	305		301
Franchise agreements	37		40
Deferred employee benefit plan costs	347		348
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	159		154
Deferred pollution control costs	35		25
Other	56		41
Total Regulatory Assets	$	1,216	$	1,206

Schedule of Regulatory Liabilities [Table Text Block]

Regulatory Liabilities:
Accumulated deferred income taxes	$	21	$	23
Asset removal costs	507		493
Storm damage reserve	27		32
Deferred gains on interest rate derivatives	85		26
Planned major maintenance	8		—
Other	1		1
Total Regulatory Liabilities	$	649	$	575

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

years:

Year	Increase	Amount (Millions)
2012	2.3%	$52.1
2011	2.4%	$52.8

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

e following years:

Year	Action			Amount (Millions)
2012	2.1	%	Increase	$7.5
2011	2.1	%	Increase	$8.6

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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, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	$ 0	$ 21	$ 4	$ 29
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Tax	2	1	11	5
Other Comprehensive Income (Loss), Reclassification, Pension and Other Postretirement Benefit Plans, Net Gain (Loss) Recognized in Net Periodic Benefit Cost, Tax	0	0	0	0
Accumulated Other Comprehensive Income (Loss), Net of Tax	81.8		81.8		93.8
SCE&G
Other Comprehensive Income (Loss), Reclassification, Pension and Other Postretirement Benefit Plans, Net Gain (Loss) Recognized in Net Periodic Benefit Cost, Tax	0	0	0	0
Accumulated Other Comprehensive Income (Loss), Net of Tax	$ 3.1		$ 3.1		$ 3.3

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Millions, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Utility Plant, Net	$ 10,597	$ 10,047
Total Current Assets	1,361	1,491
Total Deferred Debits and Other Assets	1,518	1,520
Goodwill, Writedown	230	230
Nonutility property, accumulated depreciation	141	131
Receivables, net of allowance for uncollectible accounts	5	6
SCE&G
Utility Plant, Net	9,089	8,588
Total Current Assets	1,001	915
Total Deferred Debits and Other Assets	1,385	1,396
Receivables, net of allowance for uncollectible accounts	3	3
VIEs | SCE&G
Utility Plant, Net	644	662
Total Current Assets	201	193
Total Deferred Debits and Other Assets	$ 62	$ 61

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EMPLOYEE BENEFIT PLANS

9 Months Ended

Sep. 30, 2012

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	2012			2011			2012		2011
Three months ended September 30,
Service cost	$	5.0		$	4.5		$	1.1	$	1.0
Interest cost	10.9			10.4			2.9		3.2
Expected return on assets	(15.0		)	(15.3		)	—		—
Prior service cost amortization	1.8			1.7			0.2		0.2
Transition obligation amortization	—			—			0.2		0.1
Amortization of actuarial loss	4.5			3.1			—		0.1
Net periodic benefit cost	$	7.2		$	4.4		$	4.4	$	4.6
Nine months ended September 30,
Service cost	$	14.7		$	13.7		$	3.6	$	3.2
Interest cost	32.2			32.6			8.9		9.2
Expected return on assets	(44.6		)	(47.7		)	—		—
Prior service cost amortization	5.3			5.3			0.7		0.8
Transition obligation amortization	—			—			0.5		0.5
Amortization of actuarial loss	13.8			9.1			0.4		0.3
Net periodic benefit cost	$	21.4		$	13.0		$	14.1	$	14.0

No contribution to the pension trust will be necessary in or for 2012, nor will limitations on benefit payments apply.   As authorized by the SCPSC, SCE&G defers all pension expense related to retail electric and gas operations as a regulatory asset.  Costs totaling $4.0 million and $11.4 million were deferred for the three and nine months ended September 30, 2012, respectively. Costs totaling $2.2 million and $6.8 million were deferred for the corresponding periods in 2011.

SCE&G

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	2012			2011			2012		2011
Three months ended September 30,
Service cost	$	4.1		$	3.6		$	0.8	$	0.7
Interest cost	9.1			8.8			2.3		2.5
Expected return on assets	(12.6		)	(13.0		)	—		—
Prior service cost amortization	1.6			1.5			0.1		0.2
Amortization of actuarial loss	3.7			2.6			0.1		0.1
Net periodic benefit cost	$	5.9		$	3.5		$	3.3	$	3.5
Nine months ended September 30,
Service cost	$	11.8		$	11.0		$	2.8	$	2.5
Interest cost	27.3			27.7			7.0		7.2
Expected return on assets	(37.8		)	(40.5		)	—		—
Prior service cost amortization	4.5			4.5			0.5		0.6
Amortization of actuarial loss	11.7			7.7			0.3		0.2
Net periodic benefit cost	$	17.5		$	10.4		$	10.6	$	10.5

No contribution to the pension trust will be necessary in or for 2012, nor will limitations on benefit payments apply.   As authorized by the SCPSC, SCE&G defers all pension expense related to retail electric and gas operations as a regulatory asset. Costs totaling $4.0 million and $11.4 million were deferred for the three and nine months ended September 30, 2012, respectively. Costs totaling $2.2 million and $6.8 million were deferred for the corresponding periods in 2011.

XML

Document and Entity Information	9 Months Ended
	Sep. 30, 2012	Oct. 31, 2012
Document 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, 2012
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		131,792,649
SCE&G
Document 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, 2012
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		40,296,147

XML

COMMITMENTS AND CONTINGENCIES

9 Months Ended

Sep. 30, 2012

Commitments and Contingencies Disclosure [Text Block]

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 $12.6 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 $117.5 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $17.5 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 $78.3 million per incident, but not more than $11.7 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 policies (for itself and on behalf of Santee Cooper) with NEIL.  The policies provide coverage to the nuclear facility for property damage and outage costs up to $2.75 billion. 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. 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 $37.3 million.

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

Environmental

SCE&G

On April 13, 2012, the EPA issued a proposed rule to establish a new source performance standard for GHG emissions from fossil fuel-fired electric generating units. If enacted, the proposed rule will limit emissions of carbon dioxide from new fossil fuel-fired electric utility generating units. The Company is evaluating the proposed rule, but cannot predict when the rule will become final, if at all, or what conditions it 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, including South Carolina, 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 would have replaced CAIR and the Clean Air Transport Rule proposed in July 2010 and was aimed at addressing power plant emissions that may contribute to air pollution in other states.  The rule would have required 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 U.S. Court of Appeals for the D.C. Circuit vacated CSAPR and left CAIR in place. On October 5, 2012, the EPA filed a petition for rehearing of the U. S. Court of Appeals order. Air quality control installations that SCE&G and GENCO have already completed 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 CAIR or other rules issued by the EPA are expected to be recoverable through rates.

In 2005, the EPA issued the CAMR which established a mercury emissions cap and trade program for coal-fired power plants. Numerous parties challenged the rule and, on February 8, 2008, the United States Circuit Court for the District of Columbia vacated the rule for electric utility steam generating units.  In March 2011, the EPA proposed new standards for mercury and other specified air pollutants. The rule containing the proposed new standards, which became effective on April 16, 2012, provides up to four years for facilities to meet the standards. The rule is currently being evaluated by the Company. 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 enactment of these environmental regulations, along with other factors, has resulted in the inclusion in SCE&G's most recently filed IRP of its plans to retire a total of six coal-fired units by 2018, subject to future developments in environmental regulations, among other matters.

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.  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.  SCE&G defers site assessment and cleanup costs and expects to recover them through rates. 

SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals.  These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC and the EPA.  SCE&G anticipates that major remediation activities at all these sites will continue until 2015 and will cost an additional $22.4 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 and insurance settlements.  At September 30, 2012, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $38.6 million and are included in regulatory assets.

PSNC Energy

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 $3.1 million, the estimated remaining liability at September 30, 2012. PSNC Energy expects to recover through rates any cost, net of insurance recovery, allocable to PSNC Energy arising from the remediation of these sites.

Nuclear Generation

SCE&G and Santee Cooper are parties to construction and operating agreements in which they agreed to be joint owners, and share operating costs and generation output, of two1,117MW nuclear generation units currently being constructed at the site of Summer Station, with SCE&G responsible for 55% of the cost and receiving 55% of the output, and Santee Cooper responsible for and receiving the remaining 45%.  Under these agreements, SCE&G has the primary responsibility for oversight of the construction of the New Units and will be responsible for the operation of the New Units as they come online. 

SCE&G, on behalf of itself and as agent for Santee Cooper, entered into the EPC Contract with the Consortium for the design, procurement and construction of the New Units.  SCE&G's share of the estimated cash outlays (future value, excluding AFC) totals approximately $6 billion for plant costs and related transmission infrastructure costs, which costs are projected based on historical one-year and five-year escalation rates as required by the SCPSC.

On March 30, 2012, the NRC approved and issued COLs for the New Units.  On April 19, 2012, SCE&G, on behalf of itself and as agent for Santee Cooper, issued a Full Notice to Proceed to the Consortium for construction of the New Units, allowing for the commencement of safety related aspects of the project.  The first New Unit is scheduled for substantial completion in March 2017, and the second New Unit is scheduled for substantial completion in May 2018.

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 structural 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. On July 11, 2012, SCE&G and the Consortium finalized an agreement which set SCE&G's portion of the costs for these specific claims at approximately $138 million (in 2007 dollars).  SCE&G anticipates that these additional costs, as well as other costs that may be identified from time to time, will be recoverable through rates.

On May 15, 2012, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost and construction schedule for the New Units.  This petition replaced a February 29, 2012 petition, which was withdrawn.  The updated capital cost schedule in this petition reflects an increase of $283 million (SCE&G's portion in 2007 dollars) over the cost approved in a May 2011 order.  This petition includes additional identifiable capital costs of approximately $6 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, this petition includes revised substantial completion dates for the New Units based on the March 30, 2012 issuance of the COL and costs finalized in the July 11, 2012 agreement previously discussed. The SCPSC approved the updated construction schedule and substantially all of the capital costs in this petition on November 7, 2012.

When the NRC issued the COLs for the New Units, it imposed two conditions on the COLs, with the first requiring inspection and testing of certain components of the New Units' passive cooling system, and the second 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 tsunami resulting from a massive earthquake, which severely damaged several nuclear generating units and their back-up cooling systems in Japan.  SCE&G is evaluating the

impact these conditions and requirements impose on the construction and operation of the New Units.  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.

As previously reported, SCE&G has been advised by Santee Cooper that it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation in the New Units.  Santee Cooper has entered into letters of intent with several parties that may result in one or more of them executing a power purchase agreement or acquiring a portion of Santee Cooper's ownership interest in the New Units.  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 commercial operation dates of the New Units.  Any such project cost increase or delay could be material.

SCE&G

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 $12.6 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 $117.5 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $17.5 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 $78.3 million per incident, but not more than $11.7 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 policies (for itself and on behalf of Santee Cooper) with NEIL.  The policies provide coverage to the nuclear facility for property damage and outage costs up to $2.75 billion. 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. 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 $37.3 million.

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

Environmental

On April 13, 2012, the EPA issued a proposed rule to establish a new source performance standard for GHG emissions from fossil fuel-fired electric generating units. If enacted, the proposed rule will limit emissions of carbon dioxide from new fossil fuel-fired electric utility generating units.  Consolidated SCE&G is evaluating the proposed rule, but cannot predict when the rule will become final, if at all, or what conditions it 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, including South Carolina, 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 would have replaced CAIR and the Clean Air Transport Rule proposed in July 2010 and was aimed at addressing power plant emissions that may contribute to air pollution in other states.  The rule would have required 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 U.S. Court of Appeals for the D.C. Circuit vacated CSAPR and left CAIR in place. On October 5, 2012, the EPA filed a petition for rehearing of the U. S. Court of Appeals order. Air quality control installations that SCE&G and GENCO have already completed 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 CAIR or other rules issued by the EPA are expected to be recoverable through rates.

In 2005, the EPA issued the CAMR which established a mercury emissions cap and trade program for coal-fired power plants. Numerous parties challenged the rule and, on February 8, 2008, the United States Circuit Court for the District of Columbia vacated the rule for electric utility steam generating units.  In March 2011, the EPA proposed new standards for mercury and other specified air pollutants. The rule containing the proposed new standards, which became effective on April 16, 2012, provides up to four years for facilities to meet the standards. The rule is currently being evaluated by Consolidated SCE&G. 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 enactment of these environmental regulations, along with other factors, has resulted in the inclusion in SCE&G's most recently filed IRP of its plans to retire a total of six coal-fired units by 2018, subject to future developments in environmental regulations, among other matters.

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.  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.  SCE&G defers site assessment and cleanup costs and expects to recover them through rates. 

SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals.  These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC and the EPA.  SCE&G anticipates that major remediation activities at all these sites will continue until 2015 and will cost an additional $22.4 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 and insurance settlements.  At September 30, 2012, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $38.6 million and are included in regulatory assets.

Nuclear Generation

SCE&G and Santee Cooper are parties to construction and operating agreements in which they agreed to be joint owners, and share operating costs and generation output, of two1,117-MW nuclear generation units currently being constructed at the site of Summer Station, with SCE&G responsible for 55% of the cost and receiving 55% of the output, and Santee Cooper responsible for and receiving the remaining 45%.  Under these agreements, SCE&G has the primary responsibility for oversight of the construction of the New Units and will be responsible for the operation of the New Units as they come online. 

SCE&G, on behalf of itself and as agent for Santee Cooper, entered into the EPC Contract with the Consortium for the design, procurement and construction of the New Units.  SCE&G's share of the estimated cash outlays (future value, excluding AFC) totals approximately $6 billion for plant costs and related transmission infrastructure costs, which costs are projected based on historical one-year and five-year escalation rates as required by the SCPSC.

On March 30, 2012, the NRC approved and issued COLs for the New Units.  On April 19, 2012, SCE&G, on behalf of itself and as agent for Santee Cooper, issued a Full Notice to Proceed to the Consortium for construction of the New Units, allowing for the commencement of safety related aspects of the project.  The first New Unit is scheduled for substantial completion in March 2017, and the second New Unit is scheduled for substantial completion in May 2018.

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 structural 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. On July 11, 2012, SCE&G and the Consortium finalized an agreement which set SCE&G's portion of the costs for these specific claims at approximately $138 million (in 2007 dollars).  SCE&G anticipates that these additional costs, as well as other costs that may be identified from time to time, will be recoverable through rates.

On May 15, 2012, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost and construction schedule for the New Units.  This petition replaced a February 29, 2012 petition, which was withdrawn. The updated capital cost schedule in this petition reflects an increase of $283 million (SCE&G's portion in 2007 dollars) over the cost approved in the May 2011 order.  This petition includes additional identifiable capital costs of approximately $6 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, this petition includes revised substantial completion dates for the New Units based on the March 30, 2012 issuance of the COL and costs finalized in the July 11, 2012 agreement previously discussed. The SCPSC approved the updated construction schedule and substantially all of the capital costs in this petition on November 7, 2012.

When the NRC issued the COLs for the New Units, it imposed two conditions on the COLs, with the first requiring inspection and testing of certain components of the New Units' passive cooling system, and the second 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 tsunami resulting from a massive earthquake, which severely damaged several nuclear generating units and their back-up cooling systems in Japan.  SCE&G is evaluating the impact these conditions and requirements impose on the construction and operation of the New Units.  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.

As previously reported, SCE&G has been advised by Santee Cooper that it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation in the New Units.  Santee Cooper has entered into letters of intent with several parties that may result in one or more of them executing a power purchase agreement or acquiring a portion of Santee Cooper's ownership interest in the New Units.  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 commercial operation dates of the New Units.  Any such project cost increase or delay could be material.

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CONSOLIDATED STATEMENTS OF INCOME (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Operating Revenues:
Electric Domestic Regulated Revenue	$ 714	$ 728	$ 1,851	$ 1,903
Regulated Operating Revenue, Gas	109	115	513	613
Gas-nonregulated	215	249	690	858
Regulated and Unregulated Operating Revenue	1,038	1,092	3,054	3,374
Operating Expenses [Abstract]
Fuel used in electric generation	239	277	617	739
Purchased power	9	6	20	16
Gas purchased for resale	248	291	837	1,101
Other operation and maintenance	165	166	510	501
Depreciation and amortization	89	87	267	259
Other taxes	50	50	156	153
Total Operating Expenses	800	877	2,407	2,769
Operating Income	238	215	647	605
Other Income (Expense):
Other income	13	12	39	36
Other expenses	(9)	(10)	(29)	(29)
Interest charges, net of allowance for borrowed funds used during construction	(75)	(73)	(219)	(212)
Allowance for equity funds used during construction	6	5	13	13
Total Other Expense	(65)	(66)	(196)	(192)
Income Before Income Tax Expense	173	149	451	413
Income Tax Expense	51	44	136	124
Income Available to Common Shareholders	122	105	315	289
Per Common Share Data
Basic Earnings Per Share of Common Stock (in dollars per share)	$ 0.93	$ 0.81	$ 2.41	$ 2.25
Diluted Earnings Per Share of Common Stock (in dollars per share)	$ 0.91	$ 0.81	$ 2.37	$ 2.23
Weighted Average Common Shares Outstanding (millions)
Weighted Average Number of Shares Outstanding, Basic	131,400,000	129,100,000	130,800,000	128,500,000
Weighted Average Number of Shares Outstanding, Diluted	133,800,000	130,300,000	133,100,000	129,800,000
Dividends Declared Per Share of Common Stock (in dollars per share)	$ 0.495	$ 0.485	$ 1.485	$ 1.455
Gas Distribution
Operating Revenues:
Regulated and Unregulated Operating Revenue	107	114	507	606
Operating Expenses [Abstract]
Operating Income	(7)	(11)	81	75
Electric Operations
Operating Expenses [Abstract]
Operating Income	243	225	534	487
SCE&G
Operating Revenues:
Electric Domestic Regulated Revenue	716	730	1,857	1,908
Regulated Operating Revenue, Gas	61	67	244	285
Total Operating Revenues	777	797	2,101	2,193
Operating Expenses [Abstract]
Fuel used in electric generation	240	278	622	743
Purchased power	9	6	20	16
Gas purchased for resale	38	44	134	181
Other operation and maintenance	130	132	402	391
Depreciation and amortization	73	72	220	214
Other taxes	46	45	142	139
Total Operating Expenses	536	577	1,540	1,684
Operating Income	241	220	561	509
Other Income (Expense):
Other income	0	0	0	2
Other expenses	(3)	(3)	(9)	(9)
Interest charges, net of allowance for borrowed funds used during construction	(53)	(53)	(157)	(153)
Allowance for equity funds used during construction	5	5	12	12
Total Other Expense	(51)	(51)	(154)	(148)
Income Before Income Tax Expense	190	169	407	361
Income Tax Expense	58	50	126	110
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	132	119	281	251
Net Income (Loss) Attributable to Noncontrolling Interest	3	2	9	7
Net Income (Loss) Attributable to Parent	129	117	272	244
Weighted Average Common Shares Outstanding (millions)
Dividends, Common Stock, Cash	56	51	163	150
SCE&G | Gas Distribution
Operating Expenses [Abstract]
Operating Income	(3)	(5)	27	23
SCE&G | Electric Operations
Operating Expenses [Abstract]
Operating Income	$ 244	$ 225	$ 534	$ 487

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COMMON EQUITY

9 Months Ended

Sep. 30, 2012

Stockholders' Equity Note [Abstract]

COMMON EQUITY

COMMON EQUITY

Changes in common equity during the nine months ended September 30, 2012 and 2011 were as follows:

Millions of dollars	2012			2011
Balance at January 1,	$	3,889		$	3,702
Common stock issued	73			73
Dividends declared	(194		)	(188		)
Comprehensive income	327			251
Balance as of September 30,	$	4,095		$	3,838

Authorized shares of common stock were 200 million as of September 30, 2012 and December 31, 2011.  Outstanding shares of common stock were 131.5 million and 129.9 million at September 30, 2012 and December 31, 2011, respectively.

In May 2010 SCANA entered into forward sales contracts for approximately 6.6 million common shares which, after being extended by amendments, SCANA expects to settle in the first quarter of 2013. There have been no shares issued under the forward sales contracts.

SCE&G

Stockholders' Equity Note [Abstract]

COMMON EQUITY

EQUITY

Changes in common equity during the nine months ended September 30, 2012 and 2011 were as follows:

Millions of dollars	Common Equity			Noncontrolling Interest			Total Equity
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
Balance at January 1, 2011	$	3,437		$	104		$	3,541
Capital contribution from parent	73			—			73
Dividends declared	(146		)	(5		)	(151		)
Comprehensive income	244			7			251
Balance as of September 30, 2011	$	3,608		$	106		$	3,714

Authorized shares of SCE&G common stock were 50 million as of September 30, 2012 and December 31, 2011.  Outstanding shares of common stock were 40.3 million at both September 30, 2012 and December 31, 2011. Authorized shares of SCE&G preferred stock were 20 million as of September 30, 2012 and December 31, 2011, 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 were held by SCANA during all periods presented.

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RATE AND OTHER REGULATORY MATTERS

9 Months Ended

Sep. 30, 2012

Rate Matters [Line Items]

Public Utilities Disclosure [Text Block]

RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric

SCE&G's retail electric rates are established in part by using 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 February 2012, SCE&G requested authorization to decrease the total fuel cost component of its retail electric rates to be effective the first billing cycle of May 2012. In March 2012, SCE&G, the ORS and SCEUC entered into a settlement agreement in which SCE&G agreed to recover an amount equal to its actual under-collected balance of base fuel and variable environmental costs as of April 30, 2012 in the next rate period beginning with the first billing cycle of May 2012. In April 2012, the SCPSC approved the settlement agreement and ruled among other matters that SCE&G's fuel purchasing practices and policies were reasonable and prudent for the period January 1, 2011, through December 31, 201l.

On June 29, 2012, SCE&G filed an application with the SCPSC requesting an increase in retail revenues of approximately $151.5 million or 6.61%.  SCE&G also requested a mid-period reduction to the cost of fuel component in rates, as well as a reduction in the DSM component rider to retail rates. These adjustments will reduce the overall revenue increase requested to 3.75%. In addition, SCE&G requested recovery of and a return on the net carrying value of certain generating plant assets described below. SCE&G has requested that the proposed increase be effective January 1, 2013. A public hearing on this matter has been scheduled to begin on November 26, 2012; a decision from the SCPSC is expected in late December 2012.

On May 30, 2012, SCE&G filed its annual 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 plans to retire by 2018, subject to future developments in environmental regulations, among other matters. These units have an aggregate generating capacity (summer 2012) of 730 MW. The net carrying value of these units totaled $418 million at September 30, 2012, and is identified as Plant to be Retired, Net in the condensed consolidated financial statements. Included in this amount is approximately $23 million related to a unit that SCE&G plans to retire by the end of 2012. In its June 29, 2012 application with the SCPSC, described above, SCE&G has requested recovery of and a return on the net carrying value of this unit. SCE&G plans to make similar requests for the remaining units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. SCE&G continues to depreciate these units using composite straight-line rates approved by the SCPSC while the assets are in use.

In July 2010, the SCPSC issued an order approving a 4.88% overall increase in SCE&G’s retail electric base rates and authorized an allowed return on common equity of 10.7%. The SCPSC’s order adopted various stipulations among SCE&G, the ORS and other intervening parties. Among other matters, the SCPSC’s order provided for a $48.7 million credit to SCE&G’s customers over two years to be offset by accelerated recognition of previously deferred state income tax credits.

The SCPSC has approved DSM Programs for SCE&G's customers, including the establishment of an annual rider, approved by the SCPSC, to allow recovery of the costs and lost net margin revenue associated with the DSM Programs, along with an incentive for investing in such programs. SCE&G must submit annual filings to the SCPSC regarding the DSM Programs, net lost revenues, program costs, incentives and net program benefits.  In January 2011, SCE&G submitted to the SCPSC an annual update on DSM Programs and rate rider. In May 2011, the SCPSC approved the updated rate rider, which became effective the first billing cycle of June 2011. In January 2012, SCE&G submitted to the SCPSC another annual update on DSM Programs and rate rider. In April 2012, the SCPSC approved the updated rate rider and authorized SCE&G to increase its rates to recover approximately $19.6 million related to DSM Programs as set forth in its petition. The increase became effective the first billing cycle of May 2012.

Electric – BLRA

The SCPSC has approved SCE&G's combined application pursuant to the BLRA seeking a certificate of environmental compatibility and public convenience and necessity and for a base load review order relating to the proposed construction and operation by SCE&G and Santee Cooper of the New Units at Summer Station.  Under the BLRA, the SCPSC conducted a full pre-construction prudency review of the proposed units and the engineering, procurement, and construction contract under which they are being built.  The SCPSC prudency finding is binding on all future related rate proceedings so long as the construction proceeds in accordance with schedules, estimates and projections, as approved by the SCPSC.

    In May 2011, the SCPSC approved an updated capital cost schedule sought by SCE&G that, among other matters, incorporated then-identifiable capital costs of $173.9 million (SCE&G's portion in 2007 dollars). On May 15, 2012, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost and construction schedule for the New Units.  This petition replaced a February 29, 2012 petition, which was withdrawn.  The updated capital cost schedule in this petition reflects an increase of $283 million (SCE&G's portion in 2007 dollars) over the cost approved in the May 2011 order.  This petition includes additional identifiable capital costs of approximately $6 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, this petition includes 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 (which claims are discussed in Note 9).  The SCPSC approved the updated construction schedule and substantially all of the capital costs in this petition on November 7, 2012.

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 following years:

Year	Increase	Amount (Millions)
2012	2.3%	$52.1
2011	2.4%	$52.8

Gas

SCE&G

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

Year	Action			Amount (Millions)
2012	2.1	%	Increase	$7.5
2011	2.1	%	Increase	$8.6

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 annual PGA hearing to review SCE&G's gas purchasing policies and procedures was held in November 2011 before the SCPSC. The SCPSC issued an order in January 2012 finding that SCE&G's gas purchasing policies and practices during the review period of August 1, 2010 through July 31, 2011, were reasonable and prudent and authorized the suspension of SCE&G's natural gas hedging program. The next annual PGA hearing is scheduled for November 8, 2012.

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 March 2012, the NCUC approved a five cent per therm decrease in the cost of gas component of PSNC Energy's rates. The rate adjustment was effective with the first billing cycle in April 2012. In addition, in January 2012, the NCUC approved a five cent per therm decrease in the cost of gas component of PSNC Energy's rates. This rate adjustment was effective with the first billing cycle in February 2012.

In October 2012, in connection with PSNC Energy's 2012 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, 2012.

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 liabilities which are summarized in the following tables.  Substantially all of our 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, 2012		December 31, 2011
Regulatory Assets:
Accumulated deferred income taxes	$	244	$	243
Under-collections - electric fuel adjustment clause	—		28
Environmental remediation costs	44		30
AROs and related funding	321		316
Franchise agreements	37		40
Deferred employee benefit plan costs	390		392
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	159		154
Deferred pollution control costs	35		25
Other	60		45
Total Regulatory Assets	$	1,290	$	1,279

Regulatory Liabilities:
Accumulated deferred income taxes	$	21	$	23
Asset removal costs	688		662
Storm damage reserve	27		32
Monetization of bankruptcy claim	32		34
Deferred gains on interest rate derivatives	85		26
Planned major maintenance	8		—
Other	2		1
Total Regulatory Liabilities	$	863	$	778

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 expected to be recovered in retail electric rates over periods exceeding 12 months. 

Environmental remediation costs represent costs associated with the assessment and clean-up of MGP sites currently or formerly owned by the Company.  These regulatory assets are expected to be recovered over periods of up to approximately 28 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 95 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 amountsof 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.  A significant majority of these deferred costs are expected to be recovered through utility rates over average service periods of participating employees, or up to approximately 12 years.

Planned major maintenance related to certain fossil hydro 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 hydro turbine/generation equipment maintenance.  Nuclear refueling charges are accrued during each 18-month refueling outage cycle as a component of cost of service.

Deferred losses or gains on interest rate derivatives represent the effective portions of changes in fair value and payments made or received upon termination of certain interest rate derivatives designated as cash flow hedges.  These amounts are expected to be amortized to interest expense over the lives of the underlying debt, up to approximately 30 years.

Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the installation of scrubbers at Wateree and Williams Stations pursuant to specific regulatory orders.  Such costs related to Williams Station amount to $9.1 million at September 30, 2012 and are being recovered through utility rates over approximately 30 years.  The remaining costs relate to Wateree Station and SCE&G is allowed to accrue interest on these deferred costs until such costs are approved for recovery by the SCPSC.

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, certain transmission and distribution insurance premiums and certain tree trimming and vegetation management expenditures in excess of amounts included in base rates.  During the nine months ended September 30, 2012 and 2011, SCE&G applied costs of $4.6 million and $3.6 million, respectively, to the reserve.  Pursuant to the SCPSC’s July 2010 retail electric rate order approving an electric rate increase, SCE&G suspended storm damage reserve collection through rates indefinitely.

The monetization of bankruptcy claim represents proceeds from the sale of a bankruptcy claim which are expected to be 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 or by 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.

SCE&G

Rate Matters [Line Items]

Public Utilities Disclosure [Text Block]

RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric

SCE&G's retail electric rates are established in part by using 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 February 2012, SCE&G requested authorization to decrease the total fuel cost component of its retail electric rates to be effective the first billing cycle of May 2012. In March 2012, SCE&G, the ORS and SCEUC entered into a settlement agreement in which SCE&G agreed to recover an amount equal to its actual under-collected balance of base fuel and variable environmental costs as of April 30, 2012 in the next rate period beginning with the first billing cycle of May 2012. In April 2012, the SCPSC approved the settlement agreement and ruled among other matters that SCE&G's fuel purchasing practices and policies were reasonable and prudent for the period January 1, 2011, through December 31, 201l.

On June 29, 2012, SCE&G filed an application with the SCPSC requesting an increase in retail revenues of approximately $151.5 million or 6.61%. SCE&G also requested a mid-period reduction to the cost of fuel component in rates, as well as a reduction in the DSM component rider to retail rates. These adjustments will reduce the overall revenue increase requested to 3.75%. In addition, SCE&G requested recovery of and a return on the net carrying value of certain generating plant assets described below. SCE&G has requested that the proposed increase be effective January 1, 2013. A public hearing on this matter has been scheduled to begin on November 26, 2012; a decision from the SCPSC is expected in late December 2012.

On May 30, 2012, SCE&G filed its annual 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 plans to retire by 2018, subject to future developments in environmental regulations, among other matters. These units have an aggregate generating capacity (summer 2012) of 730 MW. The net carrying value of these units totaled $418 million at September 30, 2012, and is identified as Plant to be Retired, Net in the condensed consolidated financial statements. Included in this amount is approximately $23 million related to a unit that SCE&G plans to retire by the end of 2012. In its June 29, 2012 application with the SCPSC, described above, SCE&G has requested recovery of and a return on the net carrying value of this unit. SCE&G plans to make similar requests for the remaining units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. SCE&G continues to depreciate these units using composite straight-line rates approved by the SCPSC while the assets are in use.

In July 2010, the SCPSC issued an order approving a 4.88% overall increase in SCE&G’s retail electric base rates and authorized an allowed return on common equity of 10.7%. The SCPSC’s order adopted various stipulations among SCE&G, the ORS and other intervening parties. Among other matters, the SCPSC’s order provided for a $48.7 million credit to SCE&G’s customers over two years to be offset by accelerated recognition of previously deferred state income tax credits.

The SCPSC has approved DSM Programs for SCE&G's customers, including the establishment of an annual rider, approved by the SCPSC, to allow recovery of the costs and lost net margin revenue associated with the DSM Programs, along with an incentive for investing in such programs. SCE&G must submit annual filings to the SCPSC regarding the DSM Programs, net lost revenues, program costs, incentives and net program benefits.  In January 2011, SCE&G submitted to the SCPSC an annual update on DSM Programs and rate rider. In May 2011, the SCPSC approved the updated rate rider, which became effective the first billing cycle of June 2011. In January 2012, SCE&G submitted to the SCPSC another annual update on DSM Programs and rate rider. In April 2012, the SCPSC approved the updated rate rider and authorized SCE&G to increase its rates to recover approximately $19.6 million related to DSM Programs as set forth in its petition. The increase became effective the first billing cycle of May 2012.

Electric – BLRA

The SCPSC has approved SCE&G's combined application pursuant to the BLRA seeking a certificate of environmental compatibility and public convenience and necessity and for a base load review order relating to the proposed construction and operation by SCE&G and Santee Cooper of the New Units at Summer Station.  Under the BLRA, the SCPSC conducted a full pre-construction prudency review of the proposed units and the engineering, procurement, and construction contract under which they are being built.  The SCPSC prudency finding is binding on all future related rate proceedings so long as the construction proceeds in accordance with schedules, estimates and projections, as approved by the SCPSC.

In May 2011, the SCPSC approved an updated capital cost schedule sought by SCE&G that, among other matters, incorporated then-identifiable capital costs of $173.9 million (SCE&G's portion in 2007 dollars). On May 15, 2012, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost and construction schedule for the New Units. This petition replaced a February 29, 2012 petition, which was withdrawn. The updated capital cost schedule in this petition reflects an increase of $283 million (SCE&G's portion in 2007 dollars) over the cost approved in the May 2011 order.  This petition includes additional identifiable capital costs of approximately $6 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, this petition includes 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 (which claims are discussed in Note 9).  The SCPSC approved the updated construction schedule and substantially all of the capital costs in this petition on November 7, 2012.

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 following years:

Year	Increase	Amount (Millions)
2012	2.3%	$52.1
2011	2.4%	$52.8

Gas

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

Year	Action			Amount (Millions)
2012	2.1	%	Increase	$7.5
2011	2.1	%	Increase	$8.6

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 annual PGA hearing to review SCE&G's gas purchasing policies and procedures was held in November 2011 before the SCPSC. The SCPSC issued an order in January 2012 finding that SCE&G's gas purchasing policies and practices during the review period of August 1, 2010 through July 31, 2011, were reasonable and prudent and authorized the suspension of SCE&G's natural gas hedging program. The next annual PGA hearing is scheduled for November 8, 2012.

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 of our 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, 2012		December 31, 2011
Regulatory Assets:
Accumulated deferred income taxes	$	238	$	238
Under collections – electric fuel adjustment clause	—		28
Environmental remediation costs	39		25
AROs and related funding	305		301
Franchise agreements	37		40
Deferred employee benefit plan costs	347		348
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	159		154
Deferred pollution control costs	35		25
Other	56		41
Total Regulatory Assets	$	1,216	$	1,206

Regulatory Liabilities:
Accumulated deferred income taxes	$	21	$	23
Asset removal costs	507		493
Storm damage reserve	27		32
Deferred gains on interest rate derivatives	85		26
Planned major maintenance	8		—
Other	1		1
Total Regulatory Liabilities	$	649	$	575

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 expected to be recovered in retail electric rates over periods exceeding 12 months. 

Environmental remediation costs represent costs associated with the assessment and clean-up of MGP sites currently or formerly owned by SCE&G.  These regulatory assets are expected to be recovered over periods of up to approximately 28 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 95 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 amountsof 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.  A significant majority of these deferred costs are expected to be recovered through utility rates over average service periods of participating employees, or up to approximately 12 years.

Planned major maintenance related to certain fossil hydro 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 hydro turbine/generation equipment maintenance.  Nuclear refueling charges are accrued during each 18-month refueling outage cycle as a component of cost of service.

Deferred losses or gains on interest rate derivatives represent the effective portions of changes in fair value and payments made or received upon termination of certain interest rate derivatives designated as cash flow hedges.  These amounts are expected to be amortized to interest expense over the lives of the underlying debt, up to approximately 30 years.

Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the installation of scrubbers at Wateree and Williams Stations pursuant to specific regulatory orders.  Such costs related to Williams Station amount to $9.1 million at September 30, 2012 and are being recovered through utility rates over approximately 30 years. The remaining costs relate to Wateree Station and SCE&G is allowed to accrue interest on these deferred costs until such costs are approved for recovery by the SCPSC.

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, certain transmission and distribution insurance premiums and certain tree trimming and vegetation management expenditures in excess of amounts included in base rates.  During the nine months ended September 30, 2012 and 2011, SCE&G applied costs of $4.6 million and $3.6 million, respectively, to the reserve.  Pursuant to the SCPSC’s July 2010 retail electric rate order approving an electric rate increase, SCE&G 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 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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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

9 Months Ended

Sep. 30, 2012

Accounting Policies [Abstract]

Reconciliation of the weighted average number of common shares

Reconciliations of the weighted average number of common shares for basic and dilutive purposes are as follows:

	Quarterly		Year to Date
In Millions	2012	2011	2012	2011
Weighted Average Shares Outstanding - Basic	131.4	129.1	130.8	128.5
Net effect of dilutive equity forward shares	2.4	1.2	2.3	1.3
Weighted Average Shares - Diluted	133.8	130.3	133.1	129.8

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SEGMENT OF BUSINESS INFORMATION

9 Months Ended

Sep. 30, 2012

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.

	External			Intersegment			Operating			Net
Millions of dollars	Revenue			Revenue			Income			Income
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
Three Months Ended September 30, 2011
Electric Operations	$	728		$	2		$	225		n/a
Gas Distribution	114			1			(11		)	n/a
Retail Gas Marketing	68			—			n/a			$	(5	)
Energy Marketing	180			49			n/a			2
All Other	10			102			5			(6		)
Adjustments/Eliminations	(8		)	(154		)	(4		)	114
Consolidated Total	$	1,092		$	—		$	215		$	105

Nine months Ended September 30, 2011
Electric Operations	$	1,903		$	6		$	487	n/a
Gas Distribution	606			1			75		n/a
Retail Gas Marketing	348			—			n/a		$	14
Energy Marketing	510			146			n/a		4
All Other	30			308			13		(5		)
Adjustments/Eliminations	(23		)	(461		)	30		276
Consolidated Total	$	3,374		$	—		$	605	$	289

	September 30,		December 31,
Segment Assets	2012		2011
Electric Operations	$	8,750	$	8,222
Gas Distribution	2,208		2,179
Retail Gas Marketing	121		185
Energy Marketing	91		114
All Other	1,276		1,377
Adjustments/Eliminations	1,518		1,457
Consolidated Total	$	13,964	$	13,534

SCE&G

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.

			Operating			Earnings Available
	External		Income			To Common
Millions of dollars	Revenue		(Loss)			Shareholder
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

Three Months Ended September 30, 2011
Electric Operations	$	730	$	225		n/a
Gas Distribution	67		(5		)	n/a
Adjustments/Eliminations	—		—			$	117
Consolidated Total	$	797	$	220		$	117
Nine Months Ended September 30, 2011
Electric Operations	$	1,908	$	487		n/a
Gas Distribution	285		23			n/a
Adjustments/Eliminations	—		(1		)	$	244
Consolidated Total	$	2,193	$	509		$	244

	September 30,		December 31,
Segment Assets	2012		2011
Electric Operations	$	8,750	$	8,222
Gas Distribution	648		622
Adjustments/Eliminations	2,232		2,193
Consolidated Total	$	11,630	$	11,037

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DERIVATIVE FINANCIAL INSTRUMENTS

9 Months Ended

Sep. 30, 2012

Derivative [Line Items]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

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.  The fair value of derivative instruments is determined by reference to quoted market prices of listed contracts, published quotations or, for interest rate swaps, discounted cash flow models with independently sourced data.

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 Board of Directors with regard to the management of risk and brings to the Board’s attention any 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 and financial institutions.  Cash settlements of commodity derivatives are classified as an operating activity in the condensed consolidated statements of cash flows.

The SCPSC authorized the suspension of SCE&G's natural gas hedging program in January 2012. The fair value of such derivative instruments remaining to be settled were not significant for any period presented.

PSNC Energy hedges natural gas purchasing activities using over-the-counter options and swaps and NYMEX futures and options.  PSNC Energy’s tariffs also include a provision for the recovery of actual gas costs incurred.  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 over- or under-recovery of gas costs.  These derivative financial instruments are not designated as hedges for accounting purposes.

The unrealized gains and losses on qualifying cash flow hedges of nonregulated operations are deferred in OCI.  When the hedged transactions affect earnings, the previously recorded gains and losses are reclassified from OCI 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 the fair value attributable to changes in interest rates on certain debt issuances.  These swaps may be designated as either fair value hedges or cash flow hedges.

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.  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, and for the holding company or nonregulated subsidiaries, are recorded in OCI.  Such amounts are amortized to interest expense over the term of the underlying debt and are classified as an operating activity for cash flow purposes. Ineffective portions are recognized in income.  Cash payments made or received upon termination of these financial instruments are classified as an investing activity for cash flow 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 DT)
Hedge designation	Gas Distribution	Retail Gas Marketing	Energy Marketing	Total
As of September 30, 2012
Cash flow	—	9,650,000	20,455,750	30,105,750
Not designated (a)	8,580,000	—	22,330,074	30,910,074
Total (a)	8,580,000	9,650,000	42,785,824	61,015,824
As of December 31, 2011
Cash flow	—	6,566,000	29,861,763	36,427,763
Not designated (b)	9,080,000	—	31,943,563	41,023,563
Total (b)	9,080,000	6,566,000	61,805,326	77,451,326

(a)  Includes an aggregate 5,910,000 DT related to basis swap contracts in Energy Marketing.

(b)  Includes an aggregate 9,626,000 DT related to basis swap contracts in Energy Marketing.

The Company was not party to any interest rate swaps designated as fair value hedges at September 30, 2012. The Company was party to interest rate swaps designated as fair value hedges with aggregate notional amounts of $253.2 million at December 31, 2011, and was party to interest rate swaps designated as cash flow hedges with aggregate notional amounts of $1.1 billion at September 30, 2012 and $822.6 million at December 31, 2011.

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 (c)	Value		Location (c)	Value
As of September 30, 2012
Derivatives designated as hedging instruments
Interest rate contracts	Prepayments and other	$	27	Other current liabilities	$	75
	Other deferred debits and other assets	20		Other deferred credits and other liabilities	42
Commodity contracts	Prepayments and other	2		Other current liabilities	3
	Other current liabilities	2
Total		$	51		$	120
Derivatives not designated as hedging instruments
Commodity contracts	Prepayments and other	$	2
Energy management contracts	Prepayments and other	8		Prepayments and other	$	1
	Other deferred debits and other assets	7		Other current liabilities	7
				Other deferred credits and other liabilities	7
Total		$	17		$	15

As of December 31, 2011
Derivatives designated as hedging instruments
Interest rate contracts	Prepayments and other	$	2	Other current liabilities	$	55
				Other deferred credits and other liabilities	103
Commodity contracts	Other current liabilities	1		Prepayments and other	1
				Other current liabilities	10
				Other deferred credits and other liabilities	3
Total		$	3		$	172
Derivatives not designated as hedging instruments
Energy management contracts	Prepayments and other	$	17	Prepayments and other	$	3
	Other deferred debits and other assets	10		Other current liabilities	13
				Other deferred credits and other liabilities	9
Total		$	27		$	25

(c) Asset derivatives represent unrealized gains to the Company, and liability derivatives represent unrealized losses.  In the Company’s condensed consolidated balance sheets, unrealized gain and loss positions on commodity contracts with the same counterparty are reported as either a net asset or liability, and for purposes of the above disclosure they are reported on a gross basis.

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

With regard to the Company's interest rate swaps designated as fair value hedges, the gains on those swaps and the losses on the hedged fixed rate debt are recognized in current earnings and included in interest expense. These gains and losses, combined with the amortization of deferred gains on previously terminated swaps, resulted in increases to interest expense that were insignificant for each of the three and nine months ended September 30, 2012 and were $0.9 million and $4.9 million for the three and nine months ended September 30, 2011, respectively.

Derivatives in Cash Flow Hedging Relationships

						Gain (Loss) Reclassified from
Derivatives in Cash Flow	Gain (Loss) Deferred					Deferred Accounts into Income
Hedging Relationships	in Regulatory Accounts					(Effective Portion)
Millions of dollars	(Effective Portion)					Location	Amount
	2012		2011				2012			2011
Three Months Ended September 30,
Interest rate contracts	$	23	$	(63	)	Interest expense	$	(1	)	$	(1	)
Nine Months Ended September 30,
Interest rate contracts	$	51	$	(72	)	Interest expense	$	(2	)	$	(2	)

	Gain (Loss)						Gain (Loss) Reclassified from
Derivatives in Cash Flow	Recognized in OCI,						Accumulated OCI into Income,
Hedging Relationships	net of tax						net of tax (Effective Portion)
Millions of dollars	(Effective Portion)						Location	Amount
	2012			2011				2012			2011
Three Months Ended September 30,
Interest rate contracts	$	(1	)	$	(28	)	Interest expense	$	(2	)	$	(1	)
Commodity contracts	2			(5		)	Gas purchased for resale	(1		)	(1		)
Total	$	1		$	(33	)		$	(3	)	$	(2	)
Nine Months Ended September 30,
Interest rate contracts	$	(5	)	$	(39	)	Interest expense	$	(5	)	$	(3	)
Commodity contracts	(1		)	(7		)	Gas purchased for resale	(12		)	(5		)
Total	$	(6	)	$	(46	)		$	(17	)	$	(8	)

As of September 30, 2012, the Company expects that during the next 12 months reclassifications from accumulated other comprehensive gain to earnings arising from cash flow hedges will include approximately $0.6 million as a decrease to gas cost and approximately $6.0 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels.  As of September 30, 2012, all of the Company’s commodity cash flow hedges settle by their terms before the end of 2015.

Derivatives not designated as Hedging Instruments	Gain (Loss) Recognized in Income
Millions of dollars	Location	2012			2011
Three Months Ended September 30,
Commodity contracts	Gas purchased for resale	$	—		$	—
Nine Months Ended September 30,
Commodity contracts	Gas purchased for resale	$	(1	)	$	(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, 2012 and were $0.8 million and $1.1 million for the three and nine months ended September 30, 2011, 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, surety bonds, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. the collateral agreements require a counterparty to post cash, surety bonds 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 require the Company to provide collateral upon the occurrence of specific events, primarily credit downgrades.  As of September 30, 2012 and December 31, 2011, the Company has posted $89.1 million and $140.3 million, respectively, of collateral related to derivatives with contingent provisions that are 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 the 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 were fully triggered as of September 30, 2012 and December 31, 2011, the Company would be required to post an additional $28.3 million and $50.7 million, respectively, of collateral to its counterparties.  The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of September 30, 2012 and December 31, 2011 is $117.4 million and $191.0 million, respectively.

In addition, as of September 30, 2012 and December 31, 2011, 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, 2012 and December 31, 2011, the Company could request $45.8 million and $1.1 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, 2012 and December 31, 2011 is $45.8 million and $1.1 million, respectively. In addition, at September 30, 2012, the Company may call on letters of credit in the amount of $10 million related to $12 million in commodity derivatives that are in a net asset position, compared to letters of credit of $12 million related to derivatives of $27 million at December 31, 2011.

SCE&G

Derivative [Line Items]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

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 Board of Directors with regard to the management of risk and brings to the Board’s attention any 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 SCPSC authorized the suspension of SCE&G's natural gas hedging program in January 2012.  The fair value of such derivative instruments remaining to be settled were not significant for any period presented.

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 and are classified as an operating activity for cash flow purposes.

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.  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 and are classified as an operating activity for cash flow purposes.  Ineffective portions are recognized in income.  Cash payments made or received upon termination of these financial instruments are classified as an investing activity for cash flow purposes.

Quantitative Disclosures Related to Derivatives

SCE&G was party to natural gas derivative contracts for 210,000 DT at September 30, 2012 and 2,490,000 DT at December 31, 2011.  Consolidated SCE&G was a party to interest rate swaps designated as cash flow hedges with an aggregate notional amount of $971.4 million at September 30, 2012 and $471.4 million at December 31, 2011.

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, 2012
Derivatives designated as hedging instruments
Interest rate contracts	Prepayments and other	$	27	Other current liabilities	$	72
	Other deferred debits and other assets	20		Other deferred credits and other liabilities	12
Total		$	47		$	84
As of December 31, 2011
Derivatives designated as hedging instruments
Interest rate contracts	Prepayments and other	$	1	Other current liabilities	$	2
				Other deferred credits and other liabilities	75
Total		$	1		$	77

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

						Gain (Loss) Reclassified from
Derivatives in Cash Flow	Gain (Loss) Deferred					Deferred Accounts into Income
Hedging Relationships	in Regulatory Accounts					(Effective Portion)
Millions of dollars	(Effective Portion)					Location	Amount
	2012		2011				2012			2011
Three Months Ended September 30,
Interest rate contracts	$	23	$	(63	)	Interest expense	$	(1	)	$	(1	)
Nine Months Ended September 30,
Interest rate contracts	$	51	$	(72	)	Interest expense	$	(2	)	$	(2	)

Derivatives not designated as Hedging Instruments	Gain (Loss) Recognized in Income
Millions of dollars	Location	2012		2011
Three Months Ended September 30,
Commodity contracts	Gas purchased for resale	—		—
Nine Months Ended September 30,
Commodity contracts	Gas purchased for resale	(1	)	(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, 2012 and were $0.8 million and $1.1 million for the three and nine months ended September 30, 2011, respectively.

Credit Risk Considerations

Consolidated SCE&G 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, 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, surety bonds, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. the collateral agreements require a counterparty to post cash, surety bonds 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 require Consolidated SCE&G to provide collateral upon the occurrence of specific events, primarily credit downgrades.  As of September 30, 2012 and December 31, 2011, Consolidated SCE&G has posted $42.7 million and $45.0 million, respectively, of collateral related to derivatives with contingent provisions that are 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 the noncurrent positions are recorded in Other within Deferred Debits and Other Assets on the consolidated balance sheets. If all of the contingent features underlying these instruments were fully triggered as of September 30, 2012 and December 31, 2011, Consolidated SCE&G would be required to post an additional $28.0 million and $31.7 million, respectively, of collateral to its counterparties.  The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of September 30, 2012 and December 31, 2011 is $70.7 million and $76.7 million, respectively.

In addition, as of September 30, 2012 and December 31, 2011, 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, 2012 and December 31, 2011, Consolidated SCE&G could request $45.8 million and $1.1 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, 2012 and December 31, 2011 is $45.8 million and $1.1 million, respectively.

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LONG-TERM AND SHORT-TERM DEBT

9 Months Ended

Sep. 30, 2012

Debt Instrument [Line Items]

Long-term Debt [Text Block]

LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

     In July 2012, SCE&G issued $250 million of 4.35% first mortgage bonds due February 1, 2042, which constituted a reopening of $250 million of its 4.35% first mortgage bonds issued in January 2012. Proceeds from these sales were used to repay short-term debt primarily incurred as a result of SCE&G's construction program, to finance capital expenditures and for general corporate purposes.

In January 2012, SCANA issued $250 million of 4.125% medium term notes due February 1, 2022. Proceeds from the sale were used to retire SCANA's $250 million6.25% medium term notes due February 1, 2012.

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, 2012			December 31, 2011			September 30, 2012			December 31, 2011			September 30, 2012		December 31, 2011
Lines of credit:
Committed long-term
Total	$	300		$	300		$	1,100		$	1,100		$	100	$	100
LOC advances	—			—			—			—			—		—
Weighted average interest rate	—			—			—			—			—		—
Outstanding commercial paper (270 or fewer days)	$	66		$	131		$	327		$	512		—		$	10
Weighted average interest rate	0.80		%	0.63		%	0.47		%	0.56		%	—		0.57		%
Letters of credit supported by LOC	$	3		$	3		$	0.3		$	0.3		—		—
Available	$	231		$	166		$	773		$	588		$	100	$	90

At September 30, 2012, SCANA, SCE&G (including Fuel Company) and PSNC Energy were parties to credit agreements in the amounts of $300 million, $1,100 million, of which $400 million related to Fuel Company, and $100 million, respectively. These credit agreements were 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, fossil fuel, and emission and other environmental allowances.  As of September 30, 2012, Wells Fargo Bank, National Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provided 10.0% of the aggregate $1.5 billion credit facilities, Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A. and UBS Loan Finance LLC each provided 8.0%, and Deutsche Bank AG New York Branch, Union Bank, N.A. and U.S. Bank National Association each provided 5.3%.  Three other banks provided the remaining 6.0%.

These credit agreements were amended and extended in October 2012 to expire in October 2017. In connection with the amendment and extension of the agreements, the amount of Fuel Company's credit agreement was increased to $500 million, and the other companies' credit agreements remained the same size. In addition, SCE&G entered into a new three-year credit agreement in the amount of $200 million, which is scheduled to expire in October 2015. The amended and extended credit agreements, together with SCE&G's new three-year credit agreement total an aggregate of $1.8 billion. Wells Fargo Bank, National Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provide 10.7% of the aggregate 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.

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.

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INCOME TAXES

9 Months Ended

Sep. 30, 2012

income tax [Line Items]

Income Tax, Policy [Policy Text Block]

The Company recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses. I

Income Tax Disclosure [Text Block]

INCOME TAXES

In connection with a change in method of tax accounting for certain repair costs, the Company had previously recorded approximately $38 million of unrecognized tax benefit. During the first quarter of 2012, newadministrative guidance from the Internal Revenue Service was published. Under this guidance, the Company has recognized the entire $38 million of unrecognized tax benefit. Since this change was primarily a temporary difference, the recognition of this benefit did not have a significant effect on the Company's effective tax rate. No other material changes in the status of the Company's tax positions have occurred through September 30, 2012.

The Company recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses. In connection with the recognition of tax benefits described above, during the quarter ended March 31, 2012, the Company reversed $2 million of interest expense which had been accrued during 2011.

SCE&G

income tax [Line Items]

Income Tax Disclosure [Text Block]

INCOME TAXES

In connection with a change in method of tax accounting for certain repair costs, Consolidated SCE&G had previously recorded approximately $38 million of unrecognized tax benefit. During the first quarter of 2012, newadministrative guidance from the Internal Revenue Service was published. Under this guidance, Consolidated SCE&G has recognized the entire $38 million of unrecognized tax benefit. Since this change was primarily a temporary difference, the recognition of this benefit did not have a significant effect on Consolidated SCE&G's effective tax rate. No other material changes in the status of Consolidated SCE&G's tax positions have occurred through September 30, 2012.

Consolidated SCE&G recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses. In connection with the recognition of tax benefits described above, during the quarter ended March 31, 2012, Consolidated SCE&G reversed $2 million of interest expense which had been accrued during 2011. 

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.  The fair value of derivative instruments is determined by reference to quoted market prices of listed contracts, published quotations or, for interest rate swaps, discounted cash flow models with independently sourced data.

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FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

9 Months Ended

Sep. 30, 2012

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		Significant Other
		Markets for Identical Assets		Observable Inputs
Millions of dollars		(Level 1)		(Level 2)
As of September 30, 2012
Assets -	Available for sale securities	$	8	—
	Interest rate contracts	—		$	47
	Commodity contracts	3		3
	Energy management contracts	—		15
Liabilities -	Interest rate contracts	—		117
	Commodity contracts	—		3
	Energy management contracts	—		17
As of December 31, 2011
Assets -	Available for sale securities	$	3	—
	Interest rate contracts	—		$	2
	Commodity contracts	—		1
	Energy management contracts	—		27
Liabilities -	Interest rate contracts	—		158
	Commodity contracts	1		13
	Energy management contracts	—		26

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 and 2 during any period presented.

Financial instruments for which the carrying amount may not equal estimated fair value at September 30, 2012 and December 31, 2011 were as follows:

	September 30, 2012				December 31, 2011
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	5,153.0	$	6,241.6	$	4,653.0	$	5,479.2

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.  Carrying values reflect the fair values of interest rate swaps designated as fair value hedges, based on discounted cash flow models with independently sourced market data.  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.

SCE&G

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 cashflow models with independently sourced market 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, 2012	December 31, 2011
Assets -	Interest rate contracts	$47	$1
Liabilities -	Interest rate contracts	84	77

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 and 2 during any period presented.

Financial instruments for which the carrying amount may not equal estimated fair value at September 30, 2012 and December 31, 2011 were as follows:

	September 30, 2012				December 31, 2011
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	3,753.6	$	4,661.0	$	3,241.5	$	3,920.3

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

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

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RATE AND OTHER REGULATORY MATTERS (Details 3) (USD $)	3 Months Ended	24 Months Ended															3 Months Ended	9 Months Ended
	Sep. 30, 2012	Jul. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Sep. 30, 2012 Accumulated deferred income taxes	Dec. 31, 2011 Accumulated deferred income taxes	Sep. 30, 2012 Asset Retirement Obligation Costs [Member]	Dec. 31, 2011 Asset Retirement Obligation Costs [Member]	Sep. 30, 2012 Storm damage reserve	Dec. 31, 2011 Storm damage reserve	Sep. 30, 2012 Monetization of bankruptcy claim	Dec. 31, 2011 Monetization of bankruptcy claim	Sep. 30, 2012 Deferred gains on interest rate derivatives	Dec. 31, 2011 Deferred gains on interest rate derivatives	Sep. 30, 2012 Other.	Dec. 31, 2011 Other.	Sep. 30, 2012 SCE&G	Sep. 30, 2012 SCE&G	Sep. 30, 2011 SCE&G	Dec. 31, 2011 SCE&G
Regulatory Liabilities:
Amount Recovered Through Electric Rates to Offset Turbine Expenses		$ 18,400,000
Amount Recovered Through Electric Rates to Offset Deferred Pollution, Control Costs																	9,100,000	9,100,000
Regulatory liabilities	863,000,000		778,000,000	778,000,000	21,000,000	23,000,000	688,000,000	662,000,000	27,000,000	32,000,000	32,000,000	34,000,000	85,000,000	26,000,000	2,000,000	1,000,000	649,000,000	649,000,000		575,000,000
Amount allowed to be recovered through electric rates to offset incremental storm damage costs	0																	100,000,000
Annual amount of storm damage costs which can not be offset by amounts recovered through electric rates	2.5																	2,500,000
Storm Damage Reserve Cost Applied																		$ 4,600,000	$ 3,600,000
Accrual period of nuclear refueling charges (in months)	18																18

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

9 Months Ended

Sep. 30, 2012

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 48%  and 45% of PSNC Energy’s natural gas inventory at September 30, 2012 and December 31, 2011, respectively, with a carrying value of $20.4 million and $28.7 million, respectively, through either capacity release or agency relationships.  Under the terms of the asset management agreements, PSNC Energy receives storage asset management fees.  No fees are received under supply service agreements.  The agreements expire at various times through March 31, 2013.

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.

SCE&G

Significant Accounting Policies

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

Variable Interest Entity

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

GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $480 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.

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

9 Months Ended

Sep. 30, 2012

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, 2012			December 31, 2011			September 30, 2012			December 31, 2011			September 30, 2012		December 31, 2011
Lines of credit:
Committed long-term
Total	$	300		$	300		$	1,100		$	1,100		$	100	$	100
LOC advances	—			—			—			—			—		—
Weighted average interest rate	—			—			—			—			—		—
Outstanding commercial paper (270 or fewer days)	$	66		$	131		$	327		$	512		—		$	10
Weighted average interest rate	0.80		%	0.63		%	0.47		%	0.56		%	—		0.57		%
Letters of credit supported by LOC	$	3		$	3		$	0.3		$	0.3		—		—
Available	$	231		$	166		$	773		$	588		$	100	$	90

SCE&G

Short-term Debt [Line Items]

Long-term Debt [Text Block]

LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

     In July 2012, SCE&G issued $250 million of 4.35% first mortgage bonds due February 1, 2042, which constituted a reopening of $250 million of its 4.35% first mortgage bonds issued in January 2012. Proceeds from these sales were used to repay short-term debt primarily incurred as a result of SCE&G's construction program, to finance capital expenditures and for general corporate purposes.

 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, 2012			December 31, 2011
Lines of credit:
Committed long-term
Total	$	1,100		$	1,100
LOC advances	—			—
Weighted average interest rate	—			—
Outstanding commercial paper (270 or fewer days)	$	327		$	512
Weighted average interest rate	0.47		%	0.56		%
Letters of credit supported by LOC	$	0.3		$	0.3
Available	$	773		$	588

At September 30, 2012, SCE&G and Fuel Company were parties to credit agreements in the amount of $1.1 billion, of which $400 million relates to Fuel Company. These credit agreements were 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, fossil fuel, and emission and other environmental allowances.  As of September 30, 2012, Wells Fargo Bank, National Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provided 10.0% of the aggregate $1.1 billion credit facilities, Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A. and UBS Loan Finance LLC each provided 8.0%, and Deutsche Bank AG New York Branch, Union Bank, N.A. and U.S. Bank National Association each provided 5.3%.  Three other banks provided the remaining 6.0%.

These credit agreements were amended and extended in October 2012 to expire in October 2017. In connection with the amendment and extension of the agreements, the amount of Fuel Company's credit agreement was increased to $500 million, and SCE&G's existing credit agreement remained the same size. In addition, SCE&G entered into a new three-year credit agreement in the amount of $200 million, which is scheduled to expire in October 2015. The amended and extended credit agreements, together with SCE&G's new three-year credit agreement total an aggregate of $1.4 billion. Wells Fargo Bank, National Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provide 10.7% of the aggregate 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 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.

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, 2012			December 31, 2011
Lines of credit:
Committed long-term
Total	$	1,100		$	1,100
LOC advances	—			—
Weighted average interest rate	—			—
Outstanding commercial paper (270 or fewer days)	$	327		$	512
Weighted average interest rate	0.47		%	0.56		%
Letters of credit supported by LOC	$	0.3		$	0.3
Available	$	773		$	588

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DERIVATIVE FINANCIAL INSTRUMENTS (Details 3) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011
Effect of Fair Value Hedges on Statement of Income
Reduction to interest expense for combined amount of gains on fair value hedges, losses on hedged fixed rate debt, and amortization of deferred gain on previously terminated swaps		$ 900,000		$ 4,900,000
Effect of Cash Flow Hedges on Statement of Income
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	(3,000,000)	(2,000,000)	(17,000,000)	(8,000,000)
Gain or (Loss) Deferred in Regulatory Accounts (Effective Portion), classified in interest expense	1,000,000	(33,000,000)	(6,000,000)	(46,000,000)
Derivative, Credit Risk Related Contingent Features [Abstract]
Collateral Already Posted, Aggregate Fair Value	89,100,000		89,100,000		140,300,000
Additional collateral required to be posted to counterparties if all underlying contingent features were fully triggered	28,300,000		28,300,000		50,700,000
Aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position	117,400,000		117,400,000		191,000,000
Cashcollateralrequestedfromcounterparty	45,800,000		45,800,000		1,100,000
Derivative, net asset position	45,800,000		45,800,000		1,100,000
LetterofCreditAvailableCommodityDerivatives,assetposition	10,000,000		10,000,000		12,000,000
Commodity Derivative, net asset position	12,000,000		12,000,000		27,000,000
Commodity contracts
Effect of Cash Flow Hedges on Statement of Income
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	(1,000,000)	(1,000,000)	(12,000,000)	(5,000,000)
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred	600,000
Gain or (Loss) Deferred in Regulatory Accounts (Effective Portion), classified in interest expense	(2,000,000)	5,000,000	1,000,000	7,000,000
Derivatives not designated as hedging instruments - gain (loss) recognized in income, classified in gas purchased for resale	0	0	(1,000,000)	(1,000,000)
Interest Rate Contract
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	23,000,000	(63,000,000)	51,000,000	(72,000,000)
Effect of Cash Flow Hedges on Statement of Income
Gain or (Loss) Deferred in Regulatory Accounts (Effective Portion), classified in interest expense	(1,000,000)	(1,000,000)	(2,000,000)	(2,000,000)
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	(2,000,000)	(1,000,000)	(5,000,000)	(3,000,000)
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred	6,000,000
Gain or (Loss) Deferred in Regulatory Accounts (Effective Portion), classified in interest expense	(1,000,000)	(28,000,000)	(5,000,000)	(39,000,000)
SCE&G
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	(1,000,000)	(1,000,000)
Gain (Loss) on Interest Rate Cash Flow Hedge Ineffectiveness		0.8		1.1
Derivative, Credit Risk Related Contingent Features [Abstract]
Collateral Already Posted, Aggregate Fair Value	42,700,000		42,700,000		45,000,000
Additional collateral required to be posted to counterparties if all underlying contingent features were fully triggered	28,000,000		28,000,000		31,700,000
Aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position	70,700,000		70,700,000		76,700,000
Cashcollateralrequestedfromcounterparty	45,800,000		45,800,000		1,100,000
Derivative, net asset position	45,800,000		45,800,000		1,100,000
SCE&G | Interest Rate Contract
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	23,000,000	(63,000,000)	51,000,000	(72,000,000)
Effect of Cash Flow Hedges on Statement of Income
Gain or (Loss) Deferred in Regulatory Accounts (Effective Portion), classified in interest expense	$ (1,000,000)	$ (1,000,000)	$ (2,000,000)	$ (2,000,000)

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CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Interest charges, allowance for borrowed funds used during construction	$ 3	$ 2	$ 8	$ 7
SCE&G
Interest charges, allowance for borrowed funds used during construction	$ 3	$ 2	$ 7	$ 6

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

9 Months Ended

Sep. 30, 2012

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.

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 dilutive purposes are as follows:

	Quarterly		Year to Date
In Millions	2012	2011	2012	2011
Weighted Average Shares Outstanding - Basic	131.4	129.1	130.8	128.5
Net effect of dilutive equity forward shares	2.4	1.2	2.3	1.3
Weighted Average Shares - Diluted	133.8	130.3	133.1	129.8

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 48%  and 45% of PSNC Energy’s natural gas inventory at September 30, 2012 and December 31, 2011, respectively, with a carrying value of $20.4 million and $28.7 million, respectively, through either capacity release or agency relationships.  Under the terms of the asset management agreements, PSNC Energy receives storage asset management fees.  No fees are received under supply service agreements.  The agreements expire at various times through March 31, 2013.

New Accounting Matters

Effective for the first quarter of 2012, the Company adopted accounting guidance that revises how comprehensive income is presented in its financial statements.  The adoption of this guidance has not impacted, and is not expected to impact, the Company's results of operations, cash flows or financial position.

Effective for the first quarter of 2012, the Company adopted accounting guidance that permits it to make a qualitative assessment about the likelihood of goodwill impairment each year.  Such an assessment was performed with respect to certain goodwill, and that assessment led the Company to determine that performing a two-step quantitative impairment test was unnecessary.  For other goodwill, the two-step quantitative test was performed. The adoption of this guidance has not impacted, and is not expected to impact, the Company's results of operations, cash flows or financial position.

Effective for the first quarter of 2012, the Company adopted accounting guidance that amended existing requirements for measuring fair value and for disclosing information about fair value measurements.  The adoption of this guidance has not impacted, and is not expected to impact, the Company's results of operations, cash flows or financial position.

SCE&G

Significant Accounting Policies

Significant Accounting Policies [Text Block]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Variable Interest Entity

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

GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $480 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

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.

New Accounting Matters

Effective for the first quarter of 2012, Consolidated SCE&G adopted accounting guidance that revises how comprehensive income is presented in its financial statements. The adoption of this guidance has not impacted, and is not expected to impact, Consolidated SCE&G's results of operations, cash flows or financial position.

Effective for the first quarter of 2012, Consolidated SCE&G adopted accounting guidance that amended existing requirements for measuring fair value and for disclosing information about fair value measurements.  The adoption of this guidance has not impacted, and is not expected to impact, Consolidated SCE&G's results of operations, cash flows or financial position.

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

Variable Interest Entity

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

GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $480 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.

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DERIVATIVE FINANCIAL INSTRUMENTS (Tables)

9 Months Ended

Sep. 30, 2012

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 DT)
Hedge designation	Gas Distribution	Retail Gas Marketing	Energy Marketing	Total
As of September 30, 2012
Cash flow	—	9,650,000	20,455,750	30,105,750
Not designated (a)	8,580,000	—	22,330,074	30,910,074
Total (a)	8,580,000	9,650,000	42,785,824	61,015,824
As of December 31, 2011
Cash flow	—	6,566,000	29,861,763	36,427,763
Not designated (b)	9,080,000	—	31,943,563	41,023,563
Total (b)	9,080,000	6,566,000	61,805,326	77,451,326

(a)  Includes an aggregate 5,910,000 DT related to basis swap contracts in Energy Marketing.

(b)  Includes an aggregate 9,626,000 DT 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 (c)	Value		Location (c)	Value
As of September 30, 2012
Derivatives designated as hedging instruments
Interest rate contracts	Prepayments and other	$	27	Other current liabilities	$	75
	Other deferred debits and other assets	20		Other deferred credits and other liabilities	42
Commodity contracts	Prepayments and other	2		Other current liabilities	3
	Other current liabilities	2
Total		$	51		$	120
Derivatives not designated as hedging instruments
Commodity contracts	Prepayments and other	$	2
Energy management contracts	Prepayments and other	8		Prepayments and other	$	1
	Other deferred debits and other assets	7		Other current liabilities	7
				Other deferred credits and other liabilities	7
Total		$	17		$	15

As of December 31, 2011
Derivatives designated as hedging instruments
Interest rate contracts	Prepayments and other	$	2	Other current liabilities	$	55
				Other deferred credits and other liabilities	103
Commodity contracts	Other current liabilities	1		Prepayments and other	1
				Other current liabilities	10
				Other deferred credits and other liabilities	3
Total		$	3		$	172
Derivatives not designated as hedging instruments
Energy management contracts	Prepayments and other	$	17	Prepayments and other	$	3
	Other deferred debits and other assets	10		Other current liabilities	13
				Other deferred credits and other liabilities	9
Total		$	27		$	25

(c) Asset derivatives represent unrealized gains to the Company, and liability derivatives represent unrealized losses.  In the Company’s condensed consolidated balance sheets, unrealized gain and loss positions on commodity contracts with the same counterparty are reported as either a net asset or liability, and for purposes of the above disclosure they are reported on a gross basis.

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

Derivatives in Cash Flow Hedging Relationships

						Gain (Loss) Reclassified from
Derivatives in Cash Flow	Gain (Loss) Deferred					Deferred Accounts into Income
Hedging Relationships	in Regulatory Accounts					(Effective Portion)
Millions of dollars	(Effective Portion)					Location	Amount
	2012		2011				2012			2011
Three Months Ended September 30,
Interest rate contracts	$	23	$	(63	)	Interest expense	$	(1	)	$	(1	)
Nine Months Ended September 30,
Interest rate contracts	$	51	$	(72	)	Interest expense	$	(2	)	$	(2	)

	Gain (Loss)						Gain (Loss) Reclassified from
Derivatives in Cash Flow	Recognized in OCI,						Accumulated OCI into Income,
Hedging Relationships	net of tax						net of tax (Effective Portion)
Millions of dollars	(Effective Portion)						Location	Amount
	2012			2011				2012			2011
Three Months Ended September 30,
Interest rate contracts	$	(1	)	$	(28	)	Interest expense	$	(2	)	$	(1	)
Commodity contracts	2			(5		)	Gas purchased for resale	(1		)	(1		)
Total	$	1		$	(33	)		$	(3	)	$	(2	)
Nine Months Ended September 30,
Interest rate contracts	$	(5	)	$	(39	)	Interest expense	$	(5	)	$	(3	)
Commodity contracts	(1		)	(7		)	Gas purchased for resale	(12		)	(5		)
Total	$	(6	)	$	(46	)		$	(17	)	$	(8	)

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	Gain (Loss) Recognized in Income
Millions of dollars	Location	2012			2011
Three Months Ended September 30,
Commodity contracts	Gas purchased for resale	$	—		$	—
Nine Months Ended September 30,
Commodity contracts	Gas purchased for resale	$	(1	)	$	(1	)

SCE&G

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, 2012
Derivatives designated as hedging instruments
Interest rate contracts	Prepayments and other	$	27	Other current liabilities	$	72
	Other deferred debits and other assets	20		Other deferred credits and other liabilities	12
Total		$	47		$	84
As of December 31, 2011
Derivatives designated as hedging instruments
Interest rate contracts	Prepayments and other	$	1	Other current liabilities	$	2
				Other deferred credits and other liabilities	75
Total		$	1		$	77

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

						Gain (Loss) Reclassified from
Derivatives in Cash Flow	Gain (Loss) Deferred					Deferred Accounts into Income
Hedging Relationships	in Regulatory Accounts					(Effective Portion)
Millions of dollars	(Effective Portion)					Location	Amount
	2012		2011				2012			2011
Three Months Ended September 30,
Interest rate contracts	$	23	$	(63	)	Interest expense	$	(1	)	$	(1	)
Nine Months Ended September 30,
Interest rate contracts	$	51	$	(72	)	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	Gain (Loss) Recognized in Income
Millions of dollars	Location	2012		2011
Three Months Ended September 30,
Commodity contracts	Gas purchased for resale	—		—
Nine Months Ended September 30,
Commodity contracts	Gas purchased for resale	(1	)	(1	)

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INCOME TAXES (Details) (SCE&G, USD $) In Millions, unless otherwise specified	3 Months Ended
	Sep. 30, 2012	Dec. 31, 2011
SCE&G
Changes to Unrecognized Tax Benefits
Balance at the beginning of the period		$ 38
Balance at the end of the period		38
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	2
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Other Information	38000000
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued		$ 38

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AFFILIATED TRANSACTIONS - SCEG

9 Months Ended

Sep. 30, 2012

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 $27.1 million and $22.8 million for the nine months ended September 30, 2012 and 2011, respectively.  SCE&G had approximately $2.8 million and $2.5 million payable to CGT for transportation services at September 30, 2012 and December 31, 2011, 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 $84.0 million and $146.6 million for the nine months ended September 30, 2012 and 2011, respectively.  SCE&G’s payables to SEMI for such purposes were $10.1 million and $13.2 million as of September 30, 2012 and December 31, 2011, respectively.

SCE&G owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and selling of refined coal to reduce emissions. SCE&G owned 10% of Cope Refined Coal, LLC through December 31, 2011. SCE&G accounts for these investments using the equity method.  SCE&G’s receivables from these affiliates were $10.8 million at September 30, 2012 and $8.5 million at December 31, 2011.  SCE&G’s payables to these affiliates were $10.8 million at September 30, 2012 and $8.6 million at December 31, 2011.  SCE&G’s total purchases were $87.3 million and $100.9 million for the nine months ended September 30, 2012 and 2011, respectively.  SCE&G’s total sales were $86.9 million and $100.5 million for the nine months ended September 30, 2012 and 2011, respectively.

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 the nine months ended September 30, 2012 or 2011.  At September 30, 2012 and December 31, 2011, Consolidated SCE&G owed an affiliate $49.3 million and $58.5 million, respectively.

An affiliate processes and pays invoices for Consolidated SCE&G and is reimbursed by them. Consolidated SCE&G owed $45 million and $43 million to the affiliate at September 30, 2012 and December 31, 2011, respectively, for invoices paid by the affiliate on behalf of Consolidated SCE&G.