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 June 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 July 31, 2012
SCANA Corporation	Without Par Value	131,299,288
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).

JUNE 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	7
		Condensed Consolidated Statements of Comprehensive Income	7
		Condensed Consolidated Statements of Cash Flows	7
		Notes to Condensed Consolidated Financial Statements	8
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	24
	Item 4.	Controls and Procedures	25
South Carolina Electric & Gas Company Financial Section			26
	Item 1.	Financial Statements	27
		Condensed Consolidated Balance Sheets	27
		Condensed Consolidated Statements of Income	27
		Condensed Consolidated Statements of Comprehensive Income	28
		Condensed Consolidated Statements of Cash Flows	28
		Notes to Condensed Consolidated Financial Statements	29
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	41
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	42
	Item 4.	Controls and Procedures	43
PART II. OTHER INFORMATION			44
	Item 5.	Other Information	44
	Item 6.	Exhibits	45
Signatures			46
Exhibit Index			47

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

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

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

(9) 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;

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

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

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

(13) 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;

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

(15) 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;

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

(17) labor disputes;

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

(19) changes in taxes;

(20) inflation or deflation;

(21) compliance with regulations;

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

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

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

3

DEFINITIONS

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

TERM	MEANING
AFC	Allowance for Funds Used During Construction
ANI	American Nuclear Insurers
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	June 30, 2012			December 31, 2011
Assets
Utility Plant In Service	$	11,472		$	12,000
Accumulated Depreciation and Amortization	(3,700		)	(3,836		)
Construction Work in Progress	1,790			1,482
Plant to be Retired, Net	447			—
Nuclear Fuel, Net of Accumulated Amortization	173			171
Goodwill, net of writedown of $230	230			230
Utility Plant, Net	10,412			10,047
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation of $138 and $131	307			305
Assets held in trust, net-nuclear decommissioning	90			84
Other investments	85			87
Nonutility Property and Investments, Net	482			476
Current Assets:
Cash and cash equivalents	28			29
Receivables, net of allowance for uncollectible accounts of $5 and $6	665			756
Inventories (at average cost):
Fuel and gas supply	310			313
Materials and supplies	131			129
Emission allowances	2			2
Prepayments and other	214			236
Deferred income taxes	17			26
Total Current Assets	1,367			1,491
Deferred Debits and Other Assets:
Regulatory assets	1,265			1,279
Other	223			241
Total Deferred Debits and Other Assets	1,488			1,520
Total	$	13,749		$	13,534

Millions of dollars	June 30, 2012		December 31, 2011
Capitalization and Liabilities
Common Equity	$	4,010	$	3,889
Long-Term Debt, net	4,707		4,622
Total Capitalization	8,717		8,511
Current Liabilities:
Short-term borrowings	670		653
Current portion of long-term debt	176		31
Accounts payable	251		374
Customer deposits and customer prepayments	103		103
Taxes accrued	107		154
Interest accrued	78		74
Dividends declared	65		63
Derivative financial instruments	93		77
Other	79		113
Total Current Liabilities	1,622		1,642
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,595		1,533
Deferred investment tax credits	38		40
Asset retirement obligations	483		474
Postretirement benefits	296		291
Regulatory liabilities	835		778
Other	163		265
Total Deferred Credits and Other Liabilities	3,410		3,381
Commitments and Contingencies (Note 9)	—		—
Total	$	13,749	$	13,534

See Notes to Condensed Consolidated Financial Statements.

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
Millions of dollars, except per share amounts	2012			2011			2012			2011
Operating Revenues:
Electric	$	592		$	616		$	1,137		$	1,174
Gas - regulated	127			135			404			497
Gas - nonregulated	189			249			474			610
Total Operating Revenues	908			1,000			2,015			2,281
Operating Expenses:
Fuel used in electric generation	198			251			379			462
Purchased power	4			8			10			10
Gas purchased for resale	223			297			588			810
Other operation and maintenance	170			165			345			334
Depreciation and amortization	89			86			178			172
Other taxes	53			51			106			103
Total Operating Expenses	737			858			1,606			1,891
Operating Income	171			142			409			390
Other Income (Expense):
Other income	12			11			26			24
Other expenses	(9		)	(9		)	(19		)	(19		)
Interest charges, net of allowance for borrowed funds used during construction of $3, $3, $4 and $5	(73		)	(70		)	(145		)	(139		)
Allowance for equity funds used during construction	4			5			7			8
Total Other Expense	(66		)	(63		)	(131		)	(126		)
Income Before Income Tax Expense	105			79			278			264
Income Tax Expense	33			23			85			80
Net Income	$	72		$	56		$	193		$	184
Per Common Share Data
Basic Earnings Per Share of Common Stock	$	.55		$	.44		$	1.48		$	1.44
Diluted Earnings Per Share of Common Stock	$	.54		$	.43		$	1.46		$	1.42
Weighted Average Common Shares Outstanding (millions)
Basic	130.9			128.5			130.6			128.2
Diluted	133.1			129.7			132.7			129.4
Dividends Declared Per Share of Common Stock	$	.495		$	.485		$	.990		$	.970

See Notes to Condensed Consolidated Financial Statements.

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited) 

	Three Months Ended June 30,						Six Months Ended June 30,
Millions of dollars	2012			2011			2012			2011
Net Income	$	72		$	56		$	193		$	184
Other Comprehensive Income (Loss), net of tax:
Unrealized losses on cash flow hedging activities arising during period, net of tax benefit of $2, $9, $4 and $8	(3		)	(15		)	(7		)	(13		)
Losses on cash flow hedging activities reclassified to net income, net of tax benefit of $2, $-, $9 and $4	4			1			14			6
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax of $ -, $ -, $- and $-	1			—			1			—
Other Comprehensive Income (Loss)	2			(14		)	8			(7		)
Total Comprehensive Income (1)	$	74		$	42		$	201		$	177

(1)  Accumulated other comprehensive loss totaled $86.0 million as of June 30, 2012 and $93.8 million as of December 31, 2011.

See Notes to Condensed Consolidated Financial Statements.

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited) 

	Six Months Ended June 30,
Millions of dollars	2012			2011
Cash Flows From Operating Activities:
Net income	$	193		$	184
Adjustments to reconcile net income to net cash provided from operating activities:
Earnings from equity method investments, net of distributions	—			1
Deferred income taxes, net	65			45
Depreciation and amortization	183			173
Amortization of nuclear fuel	26			14
Allowance for equity funds used during construction	(7		)	(8		)
Cash provided (used) by changes in certain assets and liabilities:
Receivables	77			210
Inventories	(25		)	8
Prepayments and other	17			57
Regulatory liabilities	28			(6		)
Accounts payable	(32		)	(93		)
Taxes accrued	(47		)	(63		)
Interest accrued	4			2
Regulatory assets	20			(28		)
Changes in other assets	(13		)	(12		)
Changes in other liabilities	(50		)	(59		)
Net Cash Provided From Operating Activities	439			425
Cash Flows From Investing Activities:
Property additions and construction expenditures	(591		)	(477		)
Proceeds from investments (including derivative collateral posted)	237			10
Purchase of investments (including derivative collateral posted)	(211		)	(13		)
Proceeds from interest rate contract settlement	13			—
Payments upon interest rate contract settlement	(51		)	(61		)
Net Cash Used For Investing Activities	(603		)	(541		)
Cash Flows From Financing Activities:
Proceeds from issuance of common stock	50			50
Proceeds from issuance of long-term debt	494			796
Repayment of long-term debt	(270		)	(623		)
Dividends	(128		)	(122		)
Short-term borrowings, net	17			126
Net Cash Provided From Financing Activities	163			227
Net (Decrease) Increase In Cash and Cash Equivalents	(1		)	111
Cash and Cash Equivalents, January 1	29			55
Cash and Cash Equivalents, June 30	$	28		$	166
Supplemental Cash Flow Information:
Cash paid for– Interest (net of capitalized interest of $4 and $5)	$	141		$	134
– Income taxes	3			—
Noncash Investing and Financing Activities:
Accrued construction expenditures	61			125
Capital leases	2			2

 See Notes to Condensed Consolidated Financial Statements.

7

SCANA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

For the Three and Six Months Ended June 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	130.9	128.5	130.6	128.2
Net effect of dilutive equity forward shares	2.2	1.2	2.1	1.2
Weighted Average Shares - Diluted	133.1	129.7	132.7	129.4

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 41%  and 45% of PSNC Energy’s natural gas inventory at June 30, 2012 and December 31, 2011, respectively, with a carrying value of $14.6 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.

8

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.

On June 29, 2012, SCE&G filed an application with the SCPSC requesting an increase in 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 set to begin on November 27, 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 things. These units have an aggregate generating capacity (summer 2012) of 730 MW. The net carrying value of these units totaled $447 million at June 30, 2012, and is identified as Plant to be Retired, Net in the 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 things, 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.

In 2010, the SCPSC approved the 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.

9

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 things, 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 the 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) in 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 to the consolidated financial statements).  A public hearing on this petition is set to begin on September 11, 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)
2011	2.4%	$52.8
2010	2.3%	$47.3

On May 30, 2012, SCE&G filed its annual request for approval of revised rates under the provisions of the BLRA. The annual request was for an overall increase of $56.7 million, or 2.5%, to its approved retail electric rates. If approved, the rate change would be effective for bills rendered on and after October 30, 2012.

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)
2011	2.1	%	Increase	$8.6
2010	2.1	%	Decrease	$10.4

On June 15, 2012, SCE&G filed with the SCPSC its quarterly monitoring report and proposed an $8.8 million, or 2.4%, overall increase to its natural gas rates under the terms of the natural gas RSA. The ORS is expected to issue an audit report by September 1, 2012, and the SCPSC is expected to issue an order by October 15, 2012. If approved, the rate adjustment would be effective with the first billing cycle in November.

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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 conducted 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 to begin on 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 tenths 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 tenths 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 December 2011, in connection with PSNC Energy's 2011 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, 2011.

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	June 30, 2012		December 31, 2011
Regulatory Assets:
Accumulated deferred income taxes	$	243	$	243
Under-collections - electric fuel adjustment clause	—		28
Environmental remediation costs	30		30
AROs and related funding	320		316
Franchise agreements	38		40
Deferred employee benefit plan costs	387		392
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	163		154
Deferred pollution control costs	32		25
Other	52		45
Total Regulatory Assets	$	1,265	$	1,279

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Regulatory Liabilities:
Accumulated deferred income taxes	$	21	$	23
Asset removal costs	680		662
Storm damage reserve	31		32
Monetization of bankruptcy claim	33		34
Deferred gains on interest rate derivatives	65		24
Planned major maintenance	5		—
Other	—		3
Total Regulatory Liabilities	$	835	$	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 17 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, although recovery periods could become longer at the direction of the SCPSC.

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 $9.2 million at June 30, 2012 and are being recovered through utility rates over approximately 30 years.  The remaining costs relate to Wateree Station, for which the Company is seeking recovery in a current proceeding before the SCPSC.  SCE&G is allowed to accrue interest on deferred costs related to Wateree Station.

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.

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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 six months ended June 30, 2012 and 2011, SCE&G applied costs of $1.5 million and $1.8 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. SCE&G is seeking to reinstate collection of storm damage reserve amounts in a current proceeding before the SCPSC.

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 these 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 six months ended June 30, 2012 and 2011 were as follows:

Millions of dollars	2012			2011
Balance at January 1,	$	3,889		$	3,702
Common stock issued	50			50
Dividends declared	(130		)	(124		)
Comprehensive income	201			177
Balance as of June 30,	$	4,010		$	3,805

Authorized shares of common stock were 200 million as of June 30, 2012 and December 31, 2011.  Outstanding shares of common stock were 131.0 million and 129.9 million at June 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 amendment dated October 26, 2011, are to be settled by December 31, 2012, though settlement may be effected later upon mutual agreement of all parties to the contracts.  SCANA expects to amend the forward sales contracts further and to settle them 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 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 of 6.25% 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	June 30, 2012			December 31, 2011			June 30, 2012			December 31, 2011			June 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)	$	84		$	131		$	586		$	512		—			$	10
Weighted average interest rate	0.88		%	0.63		%	0.49		%	0.56		%	—		%	0.57		%
Letters of credit supported by LOC	$	3		$	3		$	0.3		$	0.3		—			—
Available	$	213		$	166		$	514		$	588		$	100		$	90

SCANA, SCE&G (including Fuel Company) and PSNC Energy are parties to credit agreements in the amounts of $300 million, $1.1 billion, of which $400 million relates to Fuel Company, and $100 million, respectively, which expire October 23, 2015.  These credit agreements are used for general corporate purposes, including liquidity support for each company’s commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, fossil fuel, and emission and other environmental allowances.  These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provide 10.0% 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 provide 8.0%, and Deutsche Bank AG New York Branch, Union Bank, N.A. and U.S. Bank National Association each provide 5.3%.  Three other banks provide the remaining 6.0%. These bank credit facilities support the issuance of commercial paper by SCANA, SCE&G (including Fuel Company) and PSNC Energy. When the commercial paper markets are dislocated (due to either price or availability constraints), the credit facilities are available to support the borrowing needs of SCANA, SCE&G (including Fuel Company) and PSNC Energy.

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 June 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 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 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.

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 other comprehensive income.  When the hedged transactions affect earnings, the previously recorded gains and losses are reclassified from other comprehensive income 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 supply futures and swaps are designated as hedges for accounting purposes.

Interest Rate Swaps

The Company uses 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 are designated as either fair value hedges or cash flow hedges.

The Company uses swaps to synthetically convert fixed rate debt to variable rate debt.  These swaps are designated as fair value hedges.  Periodic payments to or receipts from swap counterparties are recorded within interest expense and are classified as an operating activity in the consolidated statements of cash flows.  In addition, gains on certain swaps that were terminated prior to maturity of the underlying debt instruments are being amortized to interest expense over the life of the debt they hedged.

The Company synthetically converts variable rate debt to fixed rate debt using swaps that are designated as cash flow hedges.  Periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense and are classified as an operating activity for cash flow purposes.

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 other comprehensive income.  Such amounts are amortized to

interest expense over the term of the underlying debt. Ineffective portions are recognized in income.  Cash payments made or received upon termination of these financial instruments are classified as an investing activity in the consolidated statements of cash flows.

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 June 30, 2012
Cash flow	—	6,573,000	24,849,638	31,422,638
Not designated (a)	9,520,000	—	26,574,637	36,094,637
Total (a)	9,520,000	6,573,000	51,424,275	67,517,275
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 6,952,000 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 June 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 $1.0 billion at June 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 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 June 30, 2012
Derivatives designated as hedging instruments
Interest rate contracts	Prepayments and other	$	20	Other current liabilities	$	79
	Other deferred debits and other assets	8		Other deferred credits and other liabilities	41
Commodity contracts	Prepayments and other	2
	Other current liabilities	2		Other current liabilities	4
				Other deferred credits and other liabilities	2
Total		$	32		$	126
Derivatives not designated as hedging instruments
Energy management contracts	Prepayments and other	$	11	Prepayments and other	$	2
	Other deferred debits and other assets	10		Other current liabilities	10
				Other deferred credits and other liabilities	9
Total		$	21		$	21

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 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 as discussed above, resulted in increases to interest expense that were insignificant for each of the three and six months ended June 30, 2012 and were $1.5 million and $4.0 million for the three and six months ended June 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 June 30,
Interest rate contracts	$	(2	)	$	(15	)	Interest expense	$	—		$	—
Six Months Ended June 30,
Interest rate contracts	$	28		$	(9	)	Interest expense	$	(1	)	$	(1	)

	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 June 30,
Interest rate contracts	$	(4	)	$	(14	)	Interest expense	$	(1	)	$	(1	)
Commodity contracts	1			(1		)	Gas purchased for resale	(3		)	—
Total	$	(3	)	$	(15	)		$	(4	)	$	(1	)
Six Months Ended June 30,
Interest rate contracts	$	(4	)	$	(11	)	Interest expense	$	(3	)	$	(2	)
Commodity contracts	(3		)	(2		)	Gas purchased for resale	(11		)	(4		)
Total	$	(7	)	$	(13	)		$	(14	)	$	(6	)

As of June 30, 2012, the Company expects that during the next 12 months reclassifications from accumulated other comprehensive loss to earnings arising from cash flow hedges will include approximately $2.0 million as an increase to gas cost and approximately $6.7 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels.  As of June 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
Second Quarter
Commodity contracts	Gas purchased for resale	$	—		$	—
Year to Date
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 six months ended June 30, 2012 and 2011.

Credit Risk Considerations

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 June 30, 2012 and December 31, 2011, the Company has posted $116.1 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 June 30, 2012 and December 31, 2011, the Company would be required to post an additional $18.0 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 June 30, 2012 and December 31, 2011 is $134.1 million and $191.0 million, respectively.

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 June 30, 2012
Assets -	Available for sale securities	$	8	—
	Interest rate contracts	—		$	28
	Commodity contracts	1		2
	Energy management contracts	—		21
Liabilities -	Interest rate contracts	—		120
	Commodity contracts	1		6
	Energy management contracts	1		22
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 June 30, 2012 and December 31, 2011 were as follows:

	June 30, 2012				December 31, 2011
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	4,883.6	$	5,835.0	$	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.

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 June 30,
Service cost	$	4.9		$	4.6		$	1.2	$	1.1
Interest cost	10.6			11.1			3.0		3.0
Expected return on assets	(14.8		)	(16.2		)	—		—
Prior service cost amortization	1.8			1.8			0.3		0.3
Transition obligation amortization	—			—			0.1		0.2
Amortization of actuarial loss	4.6			3.0			0.2		0.1
Net periodic benefit cost	$	7.1		$	4.3		$	4.8	$	4.7
Six months ended June 30,
Service cost	$	9.7		$	9.2		$	2.5	$	2.2
Interest cost	21.3			22.2			6.0		6.0
Expected return on assets	(29.6		)	(32.4		)	—		—
Prior service cost amortization	3.5			3.6			0.5		0.6
Transition obligation amortization	—			—			0.3		0.4
Amortization of actuarial loss	9.3			6.0			0.4		0.2
Net periodic benefit cost	$	14.2		$	8.6		$	9.7	$	9.4

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 $3.7 million and $7.4 million were deferred for the three and six months ended June 30, 2012, respectively. Costs totaling $2.3 million and $4.6 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

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.  EPA's proposed rule covers only GHGs from new sources.  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 replaces CAIR and the Clean Air Transport Rule proposed in July 2010 and is aimed at addressing power plant emissions that may contribute to air pollution in other states.  The rule requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide.  On December 30, 2011, the United States Court of Appeals for the District of Columbia issued an order staying CSAPR and reinstating CAIR pending resolution of an appeal of CSAPR. Air quality control installations that SCE&G and GENCO have already completed should assist the Company in complying with CSAPR and the reinstated CAIR.  The Company will continue to pursue strategies to comply with all applicable environmental regulations.  Any costs incurred to comply with CAIR, CSAPR, or other rules issued by the EPA in the future 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 things.

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 these sites will continue until 2015 and will cost an additional $7.9 million, which is accrued in Other within Deferred Credits and Other Liabilities on the consolidated balance sheet.  SCE&G expects to recover any cost arising from the remediation of MGP sites through rates and insurance settlements.  At June 30, 2012, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $24.3 million and are included in regulatory assets.

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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 June 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 to be 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, has 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 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 the 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) in 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 modules for the New Units and unanticipated rock conditions at the site.  A public hearing on this petition is set to begin on September 11, 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

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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.

	External			Intersegment			Operating			Net
Millions of dollars	Revenue			Revenue			Income			Income
Three Months Ended June 30, 2012
Electric Operations	$	592		$	3		$	164		n/a
Gas Distribution	126			—			5			n/a
Retail Gas Marketing	71			—			—			$	(3	)
Energy Marketing	118			23			—			2
All Other	10			103			4			(4		)
Adjustments/Eliminations	(9		)	(129		)	(2		)	77
Consolidated Total	$	908		—			$	171		$	72
Six Months Ended June 30, 2012
Electric Operations	$	1,137		$	5		$	291		n/a
Gas Distribution	400			—			88			n/a
Retail Gas Marketing	224			—			n/a			$	8
Energy Marketing	250			49			n/a			4
All Other	21			209			11			1
Adjustments/Eliminations	(17		)	(263		)	19			180
Consolidated Total	$	2,015		—			$	409		$	193
Three Months Ended June 30, 2011
Electric Operations	$	616		$	2		$	140		n/a
Gas Distribution	132			—			2			n/a
Retail Gas Marketing	78			—			n/a			$	(3	)
Energy Marketing	172			52			n/a			1
All Other	10			104			3			—
Adjustments/Eliminations	(8		)	(158		)	(3		)	58
Consolidated Total	$	1,000		—			$	142		$	56

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Six Months Ended June 30, 2011
Electric Operations	$	1,174		$	4		$	262	n/a
Gas Distribution	492			—			86		n/a
Retail Gas Marketing	280			—			n/a		$	19
Energy Marketing	330			97			n/a		2
All Other	20			206			8		1
Adjustments/Eliminations	(15		)	(307		)	34		162
Consolidated Total	$	2,281		—			$	390	$	184

	June 30,		December 31,
Segment Assets	2012		2011
Electric Operations	$	8,589	$	8,222
Gas Distribution	2,201		2,179
Retail Gas Marketing	141		185
Energy Marketing	93		114
All Other	1,250		1,377
Adjustments/Eliminations	1,475		1,457
Consolidated Total	$	13,749	$	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 SIX MONTHS ENDED JUNE 30, 2012

AS COMPARED TO THE CORRESPONDING PERIODS IN 2011

Earnings Per Share

Earnings per share was as follows:

	Second Quarter		Year to Date
Millions of dollars	2012	2011	2012	2011
Basic earnings per share	$0.55	$0.44	$1.48	$1.44
Diluted earnings per share	$0.54	$0.43	$1.46	$1.42

Second Quarter

Basic earnings per share increased by $.17 due to higher electric margin and by $.04 due to higher gas margin. These increases were partially offset by $.03 due to higher operating expenses, by $.02 due to higher depreciation expense, by $.01 due to higher interest expense, by $.01 due to higher property taxes, by dilution from additional shares outstanding of $.01 and by $.02 due to other items.

Year to Date

Basic earnings per share increased by $.25 due to higher electric margin. This increase was partially offset by $.04 due to lower gas margin, by $.06 due to higher operating expenses, by $.03 due to higher depreciation expense, by $.02 due to higher interest expense, by $.02 due to higher property taxes, by dilution from additional shares outstanding of $.03 and by $.01 due to other items. 

Diluted Earnings Per Share

In May 2010, SCANA entered into equity forward contracts for 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 plans to extend the equity forward contracts and 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

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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:

			Second Quarter						Year to Date
Millions of dollars	2012		% Change		2011		2012		% Change		2011
Operating revenues	$	594.1	(3.8	)%	$	617.7	$	1,141.4	(3.1	)%	$	1,178.0
Less:  Fuel used in generation	199.2		(21.0	)%	252.2		381.9		(17.9	)%	464.9
Purchased power	4.6		(41.8	)%	7.9		10.3		1.0	%	10.2
Margin	$	390.3	9.1	%	$	357.6	$	749.2	6.6	%	$	702.9

Second Quarter

Margin increased approximately $13.3 million due to base rate increases under the BLRA, by $12.9 million due to customer growth and higher average use and by $1.9 million due to lower fuel handling expenses.

Year to Date

Margin increased approximately $25.9 million due to base rate increases under the BLRA, by $13.1 million due to customer growth and higher average use and by $3.4 million due to lower fuel handling expenses.

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

		Second Quarter				Year to Date
Classification	2012	% Change		2011	2012	% Change		2011
Residential	1,799	(10.5	)%	2,009	3,490	(14.2	)%	4,068
Commercial	1,846	(4.8	)%	1,939	3,490	(2.8	)%	3,589
Industrial	1,514	(1.3	)%	1,534	2,899	(1.7	)%	2,950
Other	147	1.4	%	145	282	3.7	%	272
Total Retail Sales	5,306	(5.7	)%	5,627	10,161	(6.6	)%	10,879
Wholesale	623	20.5	%	517	1,257	26.0	%	998
Total Sales	5,929	(3.5	)%	6,144	11,418	(3.9	)%	11,877

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:

			Second Quarter						Year to Date
Millions of dollars	2012		% Change		2011		2012		% Change		2011
Operating revenues	$	125.4	(5.6	)%	$	132.8	$	400.0	(18.8	)%	$	492.6
Less:  Gas purchased for resale	57.3		(18.5	)%	70.3		185.9		(35.0	)%	285.9
Margin	$	68.1	9.0	%	$	62.5	$	214.1	3.6	%	$	206.7

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

		Second Quarter				Year to Date
Classification (in thousands)	2012	% Change		2011	2012	% Change		2011
Residential	3,142	1.6	%	3,091	18,168	(22.4	)%	23,400
Commercial	4,682	7.3	%	4,365	13,048	(11.3	)%	14,715
Industrial	5,025	15.6	%	4,347	10,470	8.2	%	9,673
Transportation	8,928	14.5	%	7,796	19,152	10.3	%	17,369
Total	21,777	11.1	%	19,599	60,838	(6.6	)%	65,157

Second 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 1.7% residential and 2.4% commercial customer growth.  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

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 $2.4 million primarily due to 1.5% residential and 2.5% commercial customer growth.  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:

				Second Quarter							Year to Date
Millions	2012			% Change		2011			2012		% Change		2011
Operating revenues	$	71.3		(8.4	)%	$	77.8		$	224.1	(20.0	)%	$	280.1
Net Income (Loss)	(3.2		)	10.3	%	(2.9		)	7.9		(58.0	)%	18.8

Second Quarter

Changes in operating revenues and net loss are 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 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:

			Second Quarter						Year to Date
Millions	2012		% Change		2011		2012		% Change		2011
Operating revenues	$	140.9	(36.8	)%	$	222.8	$	299.0	(29.9	)%	$	426.4
Net Income	1.8		50.0	%	1.2		3.6		50.0	%	2.4

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:

			Second Quarter						Year to Date
Millions of dollars	2012		% Change		2011		2012		% Change		2011
Other operation and maintenance	$	169.8	3.1	%	$	164.7	$	344.9	3.1	%	$	334.4
Depreciation and amortization	89.2		3.6	%	86.1		177.9		3.5	%	171.9
Other taxes	52.9		4.1	%	50.8		105.5		2.8	%	102.6

Second Quarter

Other operation and maintenance expenses increased by $9.0 million due to higher compensation and other benefits and by $1.9 million due to higher generation, transmission and distribution expenses. This increase was partially offset by $5.6 million due to lower customer service expense and general expenses. Depreciation and amortization expense increased in 2012 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 $6.5 million due to higher compensation and other benefits. This increase was partially offset by $6.2 million due to lower customer service expense and general expenses, including bad debt expense. Depreciation and amortization expense increased in 2012 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 the activities of certain non-regulated subsidiaries.

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 (and the effective rate) for the three and six months ended June 30, 2012 were higher than the same period in 2011 primarily due to higher income before taxes, which excludes the allowance for equity funds used during construction, a nontaxable item.

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 six and 12 months ended June 30, 2012 was 2.83 and 2.89, 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 June 30, 2012, the Company had net available liquidity of approximately $854.7 million. 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 17 years and bears an average interest cost of 6.0%.  A significant portion of 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.

SCANA issued $50 million of stock during the six months ended June 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 of 6.25% medium term notes due February 1, 2012.

The Company has paid approximately $38 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 to be 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, has 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 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.

23

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 the 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.  A public hearing on this petition is set to begin on September 11, 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 a significant portion 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 issued an order in January 2012 and authorized the suspension of SCE&G's natural gas hedging program. The fair value of SCE&G's derivative instruments remaining to be settled were not significant for any period presented. See Note 6 of the condensed consolidated financial statements.  The following tables provide information about the Company’s financial instruments that are sensitive to changes in natural gas prices.  Weighted average settlement prices are per 10,000 DT.  Fair value represents quoted market prices for these or similar instruments.

24

Expected Maturity:
Futures Contracts			Options
				Purchased Call	Purchased Put	Sold Call	Sold Put
2012	Long	Short	2012	(Long)	(Short)	(Short)	(Long)
Settlement Price (a)	3.01	4.01	Strike Price (a)	3.99	2.40	2.80	2.40
Contract Amount (b)	10.1	—	Contract Amount (b)	17.4	0.1	0.2	0.1
Fair Value (b)	9.4	—	Fair Value (b)	0.5	—	—	—
2013			2013
Settlement Price (a)	3.51	—	Strike Price (a)	3.88	—	—	—
Contract Amount (b)	10.8	—	Contract Amount (b)	20.2	—	—	—
Fair Value (b)	10.6	—	Fair Value (b)	1.4	—	—	—
2014
Settlement Price (a)	4.03
Contract Amount (b)	0.2
Fair Value (b)	0.2
(a)  Weighted average, in dollars
(b)  Millions of dollars

Swaps	2012	2013	2014	2015	2016
Commodity Swaps:
Pay fixed/receive variable (b)	38.8	35.5	14.6	12.6	7.2
Average pay rate (a)	3.9562	4.5374	5.0316	5.2608	4.9875
Average received rate (a)	3.0329	3.5447	3.9464	4.1288	4.2856
Fair value (b)	29.7	27.7	11.4	9.9	6.2
Pay variable/receive fixed (b)	22.4	21.5	11.4	9.9	6.2
Average pay rate (a)	2.9942	3.5563	3.9461	4.1288	4.2856
Average received rate (a)	3.9592	4.5990	5.0402	5.2705	4.9942
Fair value (b)	29.6	27.8	14.6	12.6	7.2
Basis Swaps:
Pay variable/receive variable (b)	10.7	12.1	—	—	—
Average pay rate (a)	3.0093	3.5568	—	—	—
Average received rate (a)	2.9942	3.5436	—	—	—
Fair value (b)	10.6	12.1	—	—	—
(a) Weighted average, in dollars
(b) Millions of dollars

ITEM 4. CONTROLS AND PROCEDURES

As of June 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 June 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 June 30, 2012 that has materially affected or is reasonably likely to materially affect SCANA’s internal control over financial reporting.

25

SOUTH CAROLINA ELECTRIC & GAS COMPANY

FINANCIAL SECTION

26

Item 1. FINANCIAL STATEMENTS

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

Millions of dollars	June 30, 2012			December 31, 2011
Assets
Utility Plant In Service	$	9,763		$	10,312
Accumulated Depreciation and Amortization	(3,220		)	(3,367		)
Construction Work in Progress	1,764			1,472
Plant to be Retired, Net	447			—
Nuclear Fuel, Net of Accumulated Amortization	174			171
Utility Plant, Net ($658 and $662 related to VIEs)	8,928			8,588
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	57			52
Assets held in trust, net - nuclear decommissioning	90			84
Other investments	3			2
Nonutility Property and Investments, Net	150			138
Current Assets:
Cash and cash equivalents	14			16
Receivables, net of allowance for uncollectible accounts of $1 and $3	467			482
Affiliated receivables	7			9
Inventories (at average cost):
Fuel and gas supply	219			196
Materials and supplies	122			120
Emission allowances	2			2
Prepayments and other	166			82
Deferred income taxes	5			8
Total Current Assets ($231 and $193 related to VIEs)	1,002			915
Deferred Debits and Other Assets:
Regulatory assets	1,192			1,206
Other	159			190
Total Deferred Debits and Other Assets ($64 and $61 related to VIEs)	1,351			1,396
Total	$	11,431		$	11,037

Millions of dollars	June 30, 2012		December 31, 2011
Capitalization and Liabilities
Common equity	$	3,756	$	3,665
Noncontrolling interest	110		108
Long-Term Debt, net	3,314		3,222
Total Capitalization	7,180		6,995
Current Liabilities:
Short-term borrowings	586		512
Current portion of long-term debt	169		19
Accounts Payable	154		231
Affiliated Payables	128		136
Customer deposits and customer prepayments	54		54
Taxes accrued	139		150
Interest accrued	59		54
Dividends declared	54		39
Derivative financial instruments	75		2
Other	38		61
Total Current Liabilities	1,456		1,258
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,424		1,371
Deferred investment tax credits	38		40
Asset retirement obligations	458		449
Postretirement benefits	181		179
Regulatory liabilities	625		575
Other	69		170
Total Deferred Credits and Other Liabilities	2,795		2,784
Commitments and Contingencies (Note 9)	—		—
Total	$	11,431	$	11,037

See Notes to Condensed Consolidated Financial Statements.

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited) 

	Three Months Ended June 30,						Six Months Ended June 30,
Millions of dollars	2012			2011			2012			2011
Operating Revenues:
Electric	$	594		$	618		$	1,141		$	1,178
Gas	67			73			183			218
Total Operating Revenues	661			691			1,324			1,396
Operating Expenses:
Fuel used in electric generation	199			252			382			465
Purchased power	4			8			10			10
Gas purchased for resale	37			49			96			136
Other operation and maintenance	134			127			272			260
Depreciation and amortization	74			71			147			142
Other taxes	48			47			96			94
Total Operating Expenses	496			554			1,003			1,107
Operating Income	165			137			321			289
Other Income (Expense):
Other income	—			1			—			2
Other expenses	(3		)	(3		)	(7		)	(7		)
Interest charges, net of allowance for borrowed funds used during construction of $3, $3, $4 and $4	(52		)	(50		)	(103		)	(100		)
Allowance for equity funds used during construction	4			5			7			8
Total Other Expense	(51		)	(47		)	(103		)	(97		)
Income Before Income Tax Expense	114			90			218			192
Income Tax Expense	36			29			69			60
Net Income	78			61			149			132
Less Net Income Attributable to Noncontrolling Interest	2			2			6			5
Earnings Available to Common Shareholder	$	76		$	59		$	143		$	127
Dividends Declared on Common Stock	$	54		$	49		$	107		$	100

See Notes to Condensed Consolidated Financial Statements.

27

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
Millions of dollars	2012			2011			2012			2011
Net Income	$	78		$	61		$	149		$	132
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	78			61			149			132
Less comprehensive income attributable to noncontrolling interest	(2		)	(2		)	(6		)	(5		)
Comprehensive income available to common shareholder (1)	$	76		$	59		$	143		$	127

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

See Notes to Condensed Consolidated Financial Statements.

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
Millions of dollars	2012			2011
Cash Flows From Operating Activities:
Net income	$	149		$	132
Adjustments to reconcile net income to net cash provided from operating activities:
Losses from equity method investments	2			1
Deferred income taxes, net	56			36
Depreciation and amortization	147			142
Amortization of nuclear fuel	26			14
Allowance for equity funds used during construction	(7		)	(8		)
Cash provided (used) by changes in certain assets and liabilities:
Receivables	3			63
Inventories	(50		)	3
Prepayments and other	(74		)	43
Regulatory assets	20			(30		)
Regulatory liabilities	29			(4		)
Accounts payable	(5		)	(46		)
Taxes accrued	(11		)	(59		)
Interest accrued	5			4
Changes in other assets	24			(8		)
Changes in other liabilities	(45		)	(46		)
Net Cash Provided From Operating Activities	269			237
Cash Flows From Investing Activities:
Property additions and construction expenditures	(544		)	(425		)
Proceeds from investments (including derivative collateral posted)	98			4
Purchase of investments (including derivative collateral posted)	(121		)	(3		)
Proceeds from interest rate contract settlement	13			—
Payments upon interest rate contract settlement	—			(31		)
Net Cash Used For Investing Activities	(554		)	(455		)
Cash Flows From Financing Activities:
Proceeds from issuance of long-term debt	248			349
Repayment of long-term debt	(10		)	(164		)
Dividends	(92		)	(104		)
Contributions from parent	51			49
Short-term borrowings –affiliate, net	12			(9		)
Short-term borrowings, net	74			94
Net Cash Provided From Financing Activities	283			215
Net Increase (Decrease) In Cash and Cash Equivalents	(2		)	(3		)
Cash and Cash Equivalents, January 1	16			31
Cash and Cash Equivalents, June 30	$	14		$	28
Supplemental Cash Flow Information:
Cash paid for– Interest (net of capitalized interest of $4 and $4)	$	92		$	87
– Income taxes	—			—
Noncash Investing and Financing Activities:
Accrued construction expenditures	51			116
Capital leases	2			2

See Notes to Condensed Consolidated Financial Statements.

28

SOUTH CAROLINA ELECTRIC & GAS COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

For the Three and Six Months Ended June 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 $485 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.

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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.

On June 29, 2012, SCE&G filed an application with the SCPSC requesting an increase in 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 set to begin on November 27, 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 things. These units have an aggregate generating capacity (summer 2012) of 730 MW. The net carrying value of these units totaled $447 million at June 30, 2012, and is identified as Plant to be Retired, Net in the 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 retirements, 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 things, 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.

In 2010, the SCPSC approved the 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.

30

In May 2011, the SCPSC approved an updated capital cost schedule sought by SCE&G that, among other things, 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 the 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) in 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 to the consolidated financial statements).  A public hearing on this petition is set to begin on September 11, 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)
2011	2.4%	$52.8
2010	2.3%	$47.3

On May 30, 2012, SCE&G filed its annual request for approval of revised rates under the provisions of the BLRA. The annual request was for an overall increase of $56.7 million, or 2.5%, to its approved retail electric rates. If approved, the rate change would be effective for bills rendered on and after October 30, 2012.

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)
2011	2.1	%	Increase	$8.6
2010	2.1	%	Decrease	$10.4

On June 15, 2012, SCE&G filed with the SCPSC its quarterly monitoring report and proposed an $8.8 million, or 2.4%, overall increase to its natural gas rates under the terms of the natural gas RSA. The ORS is expected to issue an audit report by September 1, 2012, and the SCPSC is expected to issue an order by October 15, 2012. If approved, the rate adjustment would be effective with the first billing cycle in November.

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 conducted 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 to begin on November 8, 2012.

31

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	June 30, 2012		December 31, 2011
Regulatory Assets:
Accumulated deferred income taxes	$	238	$	238
Under collections – electric fuel adjustment clause	—		28
Environmental remediation costs	25		25
AROs and related funding	304		301
Franchise agreements	38		40
Deferred employee benefit plan costs	344		348
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	163		154
Deferred pollution control costs	32		25
Other	48		41
Total Regulatory Assets	$	1,192	$	1,206

Regulatory Liabilities:
Accumulated deferred income taxes	$	21	$	23
Asset removal costs	503		493
Storm damage reserve	31		32
Deferred gains on interest rate derivatives	65		24
Planned major maintenance	5		—
Other	—		3
Total Regulatory Liabilities	$	625	$	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 17 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.

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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, although recovery periods could become longer at the direction of the SCPSC.

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 $9.2 million at June 30, 2012 and are being recovered through utility rates over approximately 30 years.  The remaining costs relate to Wateree Station, for which SCE&G is seeking recovery in a current proceeding before the SCPSC.  SCE&G is allowed to accrue interest on deferred costs related to Wateree Station.

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 six months ended June 30, 2012 and 2011, SCE&G applied costs of $1.5 million and $1.8 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. SCE&G is seeking to reinstate collection of storm damage reserve amounts in a current proceeding before the SCPSC.

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 these 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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3. EQUITY

Changes in common equity during the six months ended June 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	51			—			51
Dividends declared	(103		)	(4		)	(107		)
Comprehensive income	143			6			149
Balance as of June 30, 2012	$	3,756		$	110		$	3,866
Balance at January 1, 2011	$	3,437		$	104		$	3,541
Capital contribution from parent	49			—			49
Dividends declared	(97		)	(3		)	(100		)
Comprehensive income	127			5			132
Balance as of June 30, 2011	$	3,516		$	106		$	3,622

Authorized shares of SCE&G common stock were 50 million as of June 30, 2012 and December 31, 2011.  Outstanding shares of common stock were 40.3 million at both June 30, 2012 and December 31, 2011. Authorized shares of SCE&G preferred stock were 20 million as of June 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.

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 our 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	June 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)	$	586		$	512
Weighted average interest rate	0.49		%	0.56		%
Letters of credit supported by LOC	$	0.3		$	0.3
Available	$	514		$	588

SCE&G and Fuel Company are parties to credit agreements in the amount of $1.1 billion, of which $400 million relates to Fuel Company, which expire October 23, 2015.  These credit agreements are used for general corporate purposes,

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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.  These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provide 10.0% 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 provide 8.0%, and Deutsche Bank AG New York Branch, Union Bank, N.A. and U.S. Bank National Association each provide 5.3%.  Three other banks provide the remaining 6.0%. These bank credit facilities support the issuance of commercial paper by SCE&G (including Fuel Company).  When the commercial paper markets are dislocated (due to either price or availability constraints), the credit facilities are available to support the borrowing needs of SCE&G (including Fuel Company).

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

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 June 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 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.

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 in the consolidated statements of cash flows.

Quantitative Disclosures Related to Derivatives

SCE&G was party to natural gas derivative contracts for 510,000 DT at June 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 $921.4 million at June 30, 2012 and $471.4 million at December 31, 2011.

The fair value of interest rate derivatives was reflected in the 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 June 30, 2012
Derivatives designated as hedging instruments
Interest rate contracts	Prepayments and other	$	20	Other current liabilities	$	75
	Other deferred debits and other assets	8		Other deferred credits and other liabilities	12
Total		$	28		$	87
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 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 June 30,
Interest rate contracts	$	(2	)	$	(15	)	Interest expense	$	—		$	—
Six Months Ended June 30,
Interest rate contracts	$	28		$	(9	)	Interest expense	$	(1	)	$	(1	)

Derivatives not designated as Hedging Instruments	Gain (Loss) Recognized in Income
Millions of dollars	Location	2012		2011
Second Quarter
Commodity contracts	Gas purchased for resale	—		—
Year to Date
Commodity contracts	Gas purchased for resale	(1	)	(1	)

Hedge Ineffectiveness

Other gains (losses) recognized in income representing interest rate hedge ineffectiveness were insignificant in each of the three and six months ended June 30, 2012 and 2011.

Credit Risk Considerations

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 June 30, 2012 and December 31, 2011, Consolidated SCE&G has posted $64.6 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 June 30, 2012 and December 31, 2011, Consolidated SCE&G would be required to post an additional $12.2 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 June 30, 2012 and December 31, 2011 is $76.8 million and $76.7 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		June 30, 2012	December 31, 2011
Assets -	Interest rate contracts	$28	$1
Liabilities-	Interest rate contracts	87	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 June 30, 2012 and December 31, 2011 were as follows:

	June 30, 2012				December 31, 2011
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	3,482.4	$	4,282.1	$	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.”  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.

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:

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	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2012			2011			2012		2011
Three months ended June 30,
Service cost	$	3.8		$	3.7		$	1.0	$	0.9
Interest cost	9.1			9.5			2.3		2.3
Expected return on assets	(12.6		)	(13.7		)	—		—
Prior service cost amortization	1.5			1.5			0.2		0.2
Amortization of actuarial loss	4.0			2.5			0.1		0.1
Net periodic benefit cost	$	5.8		$	3.5		$	3.6	$	3.5
Six months ended June 30,
Service cost	$	7.7		$	7.4		$	2.0	$	1.8
Interest cost	18.2			18.9			4.7		4.7
Expected return on assets	(25.2		)	(27.5		)	—		—
Prior service cost amortization	2.9			3.0			0.4		0.4
Amortization of actuarial loss	8.0			5.1			0.2		0.1
Net periodic benefit cost	$	11.6		$	6.9		$	7.3	$	7.0

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 $3.7 million and $7.4 million were deferred for the three and six months ended June 30, 2012, respectively. Costs totaling $2.3 million and $4.6 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.

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.

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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.  EPA's proposed rule covers only GHGs from new sources.  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 replaces CAIR and the Clean Air Transport Rule proposed in July 2010 and is aimed at addressing power plant emissions that may contribute to air pollution in other states.  The rule requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide.  On December 30, 2011, the United States Court of Appeals for the District of Columbia issued an order staying CSAPR and reinstating CAIR pending resolution of an appeal of CSAPR. Air quality control installations that SCE&G and GENCO have already completed should assist Consolidated SCE&G in complying with CSAPR and 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, CSAPR, or other rules issued by the EPA in the future 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 things.

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 these sites will continue until 2015 and will cost an additional $7.9 million, which is accrued in Other within Deferred Credits and Other Liabilities on the consolidated balance sheet.  SCE&G expects to recover any cost arising from the remediation of MGP sites through rates and insurance settlements.  At June 30, 2012, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $24.3 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 to be 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, has 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 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 the 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) in 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 modules for the New Units and unanticipated rock conditions at the site.  A public hearing on this petition is set to begin on September 11, 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.

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 $18.5 million and $15.8 million for the six months ended June 30, 2012 and 2011, respectively.  SCE&G had approximately $2.6 million and $2.5 million payable to CGT for transportation services at June 30, 2012 and December 31, 2011, respectively.

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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 $48.8 million and $96.7 million for the six months ended June 30, 2012 and 2011, respectively.  SCE&G’s payables to SEMI for such purposes were $10.0 million and $13.2 million as of June 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 $6.4 million at June 30, 2012 and $8.5 million at December 31, 2011.  SCE&G’s payables to these affiliates were $6.4 million at June 30, 2012 and $8.6 million at December 31, 2011.  SCE&G’s total purchases were $46.9 million and $53.3 million for the six months ended June 30, 2012 and 2011, respectively.  SCE&G’s total sales were $46.6 million and $53.1 million for the six months ended June 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 six months ended June 30, 2012 or 2011.  At June 30, 2012 and December 31, 2011, Consolidated SCE&G owed an affiliate $70.1 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 $28 million and $43 million to the affiliate at June 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 June 30, 2012
Electric Operations	$	594	$	163	n/a
Gas Distribution	67		2		n/a
Adjustments/Eliminations	—		—		$	76
Consolidated Total	$	661	$	165	$	76
Six Months Ended June 30, 2012
Electric Operations	$	1,141	$	290	n/a
Gas Distribution	183		31		n/a
Adjustments/Eliminations	—		—		$	143
Consolidated Total	$	1,324	$	321	$	143

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Three Months Ended June 30, 2011
Electric Operations	$	618	$	140		n/a
Gas Distribution	73		(2		)	n/a
Adjustments/Eliminations	—		(1		)	$	59
Consolidated Total	$	691	$	137		$	59
Six Months Ended June 30, 2011
Electric Operations	$	1,178	$	262		n/a
Gas Distribution	218		28			n/a
Adjustments/Eliminations	—		(1		)	$	127
Consolidated Total	$	1,396	$	289		$	127

	June 30,		December 31,
Segment Assets	2012		2011
Electric Operations	$	8,589	$	8,222
Gas Distribution	636		622
Adjustments/Eliminations	2,206		2,193
Consolidated Total	$	11,431	$	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 SIX MONTHS ENDED JUNE 30, 2012

AS COMPARED TO THE CORRESPONDING PERIODS IN 2011

Net Income

Net income for Consolidated SCE&G was as follows:

			Second Quarter						Year to Date
Millions of dollars	2012		% Change		2011		2012		% Change		2011
Net income	$	77.7	26.5	%	$	61.4	$	149.2	13.3	%	$	131.7

Second Quarter

Net income increased by $22.3 million due to higher electric margin and by $3.3 million due to higher gas margin.  This increase was partially offset by $3.8 million due to higher operation and maintenance expenses, higher depreciation expense of $1.9 million, higher property taxes of $1.4 million and higher interest expense of $1.7 million.

Year to Date

Net income increased by $31.7 million due to higher electric margin and by $3.4 million due to higher gas margin.  This increase was partially offset by $7.7 million due to higher operation and maintenance expenses, higher depreciation expense of $3.5 million, higher property taxes of $1.9 million and higher interest expense of $2.3 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

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:

				Second Quarter						Year to Date
Millions of dollars		2012		% Change		2011		2012		% Change		2011
Operating revenues		$	594.1	(3.8	)%	$	617.7	$	1,141.4	(3.1	)%	$	1,178.0
Less:	Fuel used in electric generation	199.2		(21.0	)%	252.2		381.9		(17.9	)%	464.9
	Purchased power	4.6		(41.8	)%	7.9		10.3		1.0	%	10.2
Margin		$	390.3	9.1	%	$	357.6	$	749.2	6.6	%	$	702.9

Second Quarter

Margin increased approximately $13.3 million due to base rate increases under the BLRA, by $12.9 million due to customer growth and higher average use and by $1.9 million due to lower fuel handling expenses.

Year to Date

Margin increased approximately $25.9 million due to base rate increases under the BLRA, by $13.1 million due to customer growth and higher average use and by $3.4 million due to lower fuel handling expenses.

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

		Second Quarter				Year to Date
Classification	2012	% Change		2011	2012	% Change		2011
Residential	1,799	(10.5	)%	2,009	3,490	(14.2	)%	4,068
Commercial	1,846	(4.8	)%	1,939	3,490	(2.8	)%	3,589
Industrial	1,514	(1.3	)%	1,534	2,899	(1.7	)%	2,950
Other	147	1.4	%	145	282	3.7	%	272
Total Retail Sales	5,306	(5.7	)%	5,627	10,161	(6.6	)%	10,879
Wholesale	623	20.5	%	517	1,257	26.0	%	998
Total Sales	5,929	(3.5	)%	6,144	11,418	(3.9	)%	11,877

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:

			Second Quarter						Year to Date
Millions of dollars	2012		% Change		2011		2012		% Change		2011
Operating revenues	$	66.8	(9.0	)%	$	73.4	$	182.5	(16.1	)%	$	217.5
Less: Gas purchased for resale	37.1		(23.5	)%	48.5		96.3		(29.3	)%	136.3
Margin	$	29.7	19.3	%	$	24.9	$	86.2	6.2	%	$	81.2

Second 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.

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

		Second Quarter				Year to Date
Classification (in thousands)	2012	% Change		2011	2012	% Change		2011
Residential	892	(8.3	)%	973	5,511	(26.6	)%	7,505
Commercial	2,463	3.5	%	2,380	6,042	(9.2	)%	6,657
Industrial	4,625	15.0	%	4,021	9,467	11.5	%	8,488
Transportation	1,111	8.2	%	1,027	2,416	8.9	%	2,219
Total	9,091	8.2	%	8,401	23,436	(5.8	)%	24,869

Second 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:

			Second Quarter						Year to Date
Millions of dollars	2012		% Change		2011		2012		% Change		2011
Other operation and maintenance	$	133.8	4.9	%	$	127.5	$	272.1	4.9	%	$	259.5
Depreciation and amortization	73.7		3.8	%	71.0		146.8		3.5	%	141.9
Other taxes	48.1		3.0	%	46.7		95.7		1.7	%	94.1

Second Quarter 

Other operation and maintenance expenses increased by $6.8 million due to higher compensation and benefits and by $1.2 million due to higher generation, transmission and distribution expenses. These increases were partially offset by $2.3 million due to lower customer service expenses and general expenses. Depreciation and amortization expense increased in 2012 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 $9.3 million due to higher generation, transmission and distribution expenses and by $3.9 due to higher compensation and benefits. This increase was partially offset by $2.4 million due to lower customer service expenses and general expenses. Depreciation and amortization expense increased in 2012 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.

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. 

Interest Expense

Interest charges increased primarily due to increased borrowings.

Income Taxes

Second Quarter

Income taxes for the three months ended June 30, 2012 were higher than the same period in 2011 primarily due to higher income before taxes, which excludes the allowance for equity funds used during construction, a nontaxable item.

Year to Date

Income taxes (and the effective tax rate) for the six months ended June 30, 2012 were higher than the same period in 2011 primarily due to higher income before taxes, which excludes the allowance for equity funds used during construction, a nontaxable item.

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 six and 12 months ended June 30, 2012 was 3.01 and 3.22, 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 June 30, 2012, Consolidated SCE&G had net available liquidity of approximately $528.2 million.  Consolidated SCE&G regularly monitors the commercial paper and short-term credit markets to optimize the timing for 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 6.0%.  A significant portion of long-term debt bears fixed interest rates or is swapped to fixed.  To further preserve liquidity, Consolidated SCE&G rigorously reviews its projected capital expenditures and operating costs and adjusts them where possible without impacting safety, reliability, and core customer service.

In 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 $13 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 to be 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, has 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 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 the 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.  A public hearing on this petition is set to begin on September 11, 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 a significant portion 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 June 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 June 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 June 30, 2012, that has materially affected or is reasonably likely to materially affect SCE&G’s internal control over financial reporting.

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PART II.  OTHER INFORMATION

ITEM 5. OTHER INFORMATION

SCANA and SCE&G:

The following information is included herein in lieu of filing it in Item 8.01 of Form 8-K:

Adoption of Revised Comprehensive Income Presentation Guidance

As further described in Note 1 to the condensed consolidated financial statements, effective for the first quarter of 2012, the Company and Consolidated SCE&G adopted accounting guidance that revised how comprehensive income is presented in its financial statements. This guidance was effective on a retrospective basis for interim and annual periods. The adoption of this guidance changed the presentation of the Company's and Consolidated SCE&G's financial statements but did not affect the calculation of net income, comprehensive income or earnings per share. The tables below include the Company's and Consolidated SCE&G's revised other comprehensive income presentation for the three most recently completed fiscal years.

SCANA
	For the year ended
Millions of Dollars	2011			2010			2009
Net Income	$	387		$	376		$	357
Less Preferred Stock Dividends of Subsidiary	—			—			(9		)
Income Available to Common Shareholders	387			376			348
Other Comprehensive Income (Loss), net of tax:
Unrealized losses on cash flow hedging activities arising during period, net of
tax of $36, $22 and $19	(58		)	(36		)	(30		)
Losses on cash flow hedging activities reclassified to net income, net of tax
of $8, $11 and $43	13			17			70
Amortization of deferred employee benefit plan costs, net of tax of $(1), $17 and $9	(2		)	27			14
Other Comprehensive Income	(47		)	8			54
Total Comprehensive Income (Loss)	$	340		$	384		$	402
Consolidated SCE&G
	For the year ended
Millions of Dollars	2011			2010			2009
Net Income	$	316		$	304		$	288
Less Preferred Stock Dividends	—			—			(9		)
Earnings Available to Common Shareholder	316			304			279
Other Comprehensive Income (Loss), net of tax:
Amortization of deferred employee benefit plan costs, net of tax of $-, $19 and $8	(1		)	31			13
Other Comprehensive Income (Loss)	(1		)	31			13
Total Comprehensive Income	315			335			292
Less Comprehensive Income attributable to noncontrolling interest	(10		)	(14		)	(7		)
Comprehensive Income Available to Common Shareholder	$	305		$	321		$	285

44

SCANA:

The following information is included herein in lieu of filing it in Item 1.01 of Form 8-K:

Indemnification

On August 2, 2012, consistent with its past practice, SCANA entered into an indemnification agreement with each of the following officers of SCANA and/or its subsidiaries in connection with their promotions in 2012: D. Russell Harris, W. Keller Kissam and Martin K. Phalen.

The indemnification agreements generally provide that SCANA will indemnify each of the covered officers for claims arising in such person's capacity as a director, officer, employee or other agent of SCANA or its subsidiaries, provided that, among other things, such officer acted in good faith and with a view to the best interests of SCANA and, with respect to any criminal proceeding, had no reasonable grounds for believing that his conduct was unlawful. The indemnification agreements also provide for payment for or reimbursement of reasonable expenses incurred by an indemnitee who is a party to a proceeding in advance of final disposition of the proceeding under certain circumstances.

The above description of the indemnification agreements is qualified in its entirety by reference to the form of indemnification agreement that is attached to this Quarterly Report on Form 10-Q as Exhibit 10.01 and incorporated herein by reference.

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.

45

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: August 3, 2012		James E. Swan, IV
		Controller
		(Principal accounting officer)

46

EXHIBIT INDEX

	Applicable to Form 10-Q of
Exhibit No.	SCANA	SCE&G	Description
3.01	X		Restated Articles of Incorporation of SCANA, as adopted on April 26, 1989 (Filed as Exhibit 3-A to Registration Statement No. 33-49145 and incorporated by reference herein)
3.02	X		Articles of Amendment dated April 27, 1995 (Filed as Exhibit 4-B to Registration Statement No. 33-62421 and incorporated by reference herein)
3.03	X		Articles of Amendment effective April 25, 2011 (Filed as Exhibit 4.03 to Registration Statement No. 333-174796 and incorporated by reference herein)
3.04		X	Restated Articles of Incorporation of SCE&G, as adopted on December 30, 2009 (Filed as Exhibit 1 to Form 8-A (File Number 000-53860) and incorporated by reference herein)
3.05	X		By-Laws of SCANA as amended and restated as of February 19, 2009 (Filed as Exhibit 4.04 to Registration Statement No. 333-174796 and incorporated by reference herein)
3.06		X	By-Laws of SCE&G as revised and amended on February 22, 2001 (Filed as Exhibit 3.05 to Registration Statement No. 333-65460 and incorporated by reference herein)
10.01	X		Form of Indemnification Agreement (Filed herewith)
31.01	X		Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)
31.02	X		Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)
31.03		X	Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)
31.04		X	Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)
32.01	X		Certification of Principal Executive Officer 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.

47

EX-10.01

Exhibit 10.01

INDEMNIFICATION AGREEMENT

This Indemnification Agreement (this “Agreement”) is made as of _____________, 2012 by and between SCANA Corporation, a South Carolina corporation (the “Corporation”), and ________________ (“Indemnitee”).

RECITALS

WHEREAS, Indemnitee is a director and/or officer of the Corporation and/or is serving at the request of the Corporation as an director and/or officer of one or more of the Corporation’s subsidiaries, and in that capacity, is performing valuable services for the Corporation; and

WHEREAS, the South Carolina Business Corporation Act of 1988, as amended (the “Act”), provides for indemnification of directors, officers, employees and agents of a corporation under certain conditions; and

WHEREAS, the Corporation’s Board of Directors (the “Board”) has evaluated the sufficiency of liability insurance and the statutory indemnification provided by the Act as to their adequacy to protect such persons against the various legal risks and potential liabilities associated with the performance of their duties, and the Board has concluded that such insurance and statutory indemnification may not be adequate protection to such persons; and

WHEREAS, the Board has determined, after due consideration of the terms of this Agreement and the various other options available to the Corporation, that this Agreement is reasonable and prudent and in the best interests of the Corporation;

NOW, THEREFORE, in consideration of the foregoing premises and the covenants contained herein, the Corporation and Indemnitee do hereby covenant and agree as follows:

1.Services to the Corporation. Indemnitee will continue to serve as a director and/or officer of the Corporation and/or one or more of the Corporation’s subsidiaries until Indemnitee’s successor is duly elected and qualified or appointed or until Indemnitee’s earlier resignation, removal or death. If Indemnitee is also an employee of the Corporation or any of its subsidiaries, nothing herein shall change Indemnitee’s status as an employee of the Corporation or such subsidiary, and nothing contained in this Agreement is intended to create in Indemnitee any right to continued employment.

2.    Definitions. As used in this Agreement:

(a)    “Covered Capacity” means present or former status as a director, officer, employee or agent of the Corporation or as a director, officer, partner, trustee, employee or agent of any other foreign or domestic corporation, partnership, joint venture, trust, employee benefit plan or other enterprise at the request of the Corporation. For purposes of this definition, Indemnitee is considered to be serving an employee benefit plan at the request of the Corporation if Indemnitee’s duties to the Corporation also impose duties on, or otherwise involve services by, Indemnitee to the plan or to participants in or beneficiaries of the plan.

(b)    “Disinterested Director” means a director of the Corporation who is not and was not a party to the Proceeding for which indemnification is sought by Indemnitee.

(c)    “Exchange Act” means the Securities Exchange Act of 1934, as amended.

(d)    “Expenses” include all direct and indirect costs, fees and expenses of any type or nature whatsoever, including, without limitation, all attorneys’ fees and costs, retainers, court costs, transcript costs, fees of experts, witness fees, travel expenses, fees of private investigators and professional advisors, duplicating costs,

#PageNum#

printing and binding costs, telephone charges, postage, delivery service fees, fax transmission charges, secretarial services and all other disbursements, obligations or expenses in connection with prosecuting, defending, preparing to prosecute or defend, investigating, being or preparing to be a witness in, settlement or appeal of, or otherwise participating in, a Proceeding, including reasonable compensation for time spent by Indemnitee for which Indemnitee is not otherwise compensated by the Corporation or any third party. “Expenses” also include Expenses incurred in connection with any appeal resulting from any Proceeding, including without limitation the principal, premium, security for, and other costs relating to any cost bond, supersedeas bond, or other appeal bond or its equivalent. “Expenses,” however, do not include amounts paid in settlement by Indemnitee or the amount of judgments or fines against Indemnitee.

(e)    References to “fines” include any excise tax assessed with respect to any employee benefit plan.

(f)    “Independent Counsel” means a law firm, or a member of a law firm, that has significant experience in matters of corporation law and neither presently is, nor in the past five years has been, retained to represent: (i) the Corporation or Indemnitee, or any party adverse to the Corporation or Indemnitee, in any matter material to either such party (other than with respect to matters concerning Indemnitee under this Agreement, or of other indemnitees under similar indemnification agreements), or (ii) any other party to the Proceeding giving rise to a claim for indemnification hereunder. Notwithstanding the foregoing, the term “Independent Counsel” does not include any person who, under the applicable standards of professional conduct then prevailing, would have a conflict of interest in representing either the Corporation or Indemnitee in an action to determine Indemnitee’s rights under this Agreement.

(g)    “Proceeding” includes any threatened, pending or completed action, suit, or proceeding, whether brought in the right of the Corporation or otherwise, whether of a civil, criminal, administrative or investigative nature and whether formal or informal, in which Indemnitee is made a party by reason of the fact that Indemnitee is or was serving in a Covered Capacity or by reason of any action taken (or failure to act) by Indemnitee or of any action (or failure to act) on Indemnitee’s part while serving in a Covered Capacity.

(h)    “South Carolina Court” means a Circuit Court of the State of South Carolina.

(i)    In connection with any merger or consolidation, references to “the Corporation” include not only the resulting or surviving corporation but also any constituent corporation or any constituent of a constituent corporation, which, if its separate existence had continued, would have had power and authority to indemnify its directors or officers and employees or agents. The intent of this provision is that a person who is or was an officer of such constituent corporation after the date hereof or is or was serving at the request of such constituent corporation as a director, officer, partner, trustee, employee or agent of any other foreign or domestic corporation, partnership, joint venture, trust, employee benefit plan or other enterprise after the date hereof, shall stand in the same position under this Agreement with respect to the resulting or surviving corporation as the person would have under this Agreement with respect to such constituent corporation if its separate existence had continued.

3.    Indemnification.

(a)    The Corporation shall indemnify Indemnitee to the fullest extent permitted by applicable law in accordance with the provisions of this Section 3(a) when Indemnitee is made a party to any Proceeding (other than a Proceeding by or in the right of the Corporation). Pursuant to this Section 3(a), Indemnitee shall be indemnified against all Expenses, judgments, liabilities, fines, penalties and amounts paid in settlement (including all interest, assessments and other charges paid or payable in connection with or in respect of such Expenses, judgments, fines, penalties and amounts paid in settlement) actually and reasonably incurred by Indemnitee or on Indemnitee’s behalf in connection with such Proceeding or any claim, issue or matter therein, if, and only if, Indemnitee’s conduct was in good faith and Indemnitee reasonably believed (a) in the case of conduct in Indemnitee’s capacity as a director, officer, employee or agent of the Corporation, that Indemnitee’s conduct was in the Corporation’s best interest, or (b) in all other cases, that Indemnitee’s conduct was at least not opposed to the

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Corporation’s best interest; and provided, further, that in the case of any criminal Proceeding, Indemnitee had no reasonable cause to believe that Indemnitee’s conduct was unlawful. Indemnitee’s conduct with respect to an employee benefit plan for a purpose that Indemnitee reasonably believed to be in the interests of the participants in and beneficiaries of the plan is conduct that satisfies the requirement of clause (b) of the immediately preceding sentence.

(b)    The Corporation shall indemnify Indemnitee to the fullest extent permitted by applicable law in accordance with the provisions of this Section 3(b) when Indemnitee is made a party to any Proceeding by or in the right of the Corporation to procure a judgment in its favor. Pursuant to this Section 3(b), Indemnitee shall be indemnified against all Expenses actually and reasonably incurred by Indemnitee or on Indemnitee’s behalf in connection with such Proceeding or any claim, issue or matter therein, if, and only if, Indemnitee’s conduct was in good faith and Indemnitee reasonably believed (a) in the case of conduct in Indemnitee’s capacity as a director, officer, employee or agent of the Corporation, that Indemnitee’s conduct was in the Corporation’s best interest, or (b) in all other cases, that Indemnitee’s conduct was at least not opposed to the Corporation’s best interest; and provided, further, that in the case of any criminal Proceeding, Indemnitee had no reasonable cause to believe that Indemnitee’s conduct was unlawful. Indemnitee’s conduct with respect to an employee benefit plan for a purpose that Indemnitee reasonably believed to be in the interests of the participants in and beneficiaries of the plan is conduct that satisfies the requirement of clause (b) of the immediately preceding sentence. No indemnification for Expenses shall be made under this Section 3(b) in respect of any claim, issue or matter as to which Indemnitee shall have been finally adjudged by a court to be liable to the Corporation, unless and only to the extent that the court in which the Proceeding was brought or the South Carolina Court shall determine upon application that, despite the adjudication of liability but in view of all the circumstances of the case, Indemnitee is fairly and reasonably entitled to indemnification.

(c)    Notwithstanding any other provision of this Agreement, to the extent that Indemnitee is wholly successful, on the merits or otherwise, in the defense of any Proceeding to which Indemnitee is a party because Indemnitee is or was serving in a Covered Capacity, the Corporation shall indemnify Indemnitee against all Expenses actually and reasonably incurred by Indemnitee in connection therewith.

(d)    Notwithstanding any other provision of this Agreement, to the extent that Indemnitee is, by reason of Indemnitee’s Covered Capacity, a witness in any Proceeding to which Indemnitee is not a party, Indemnitee shall be indemnified against all Expenses actually and reasonably incurred by Indemnitee or on Indemnitee’s behalf in connection therewith.

4.    Exclusions. Notwithstanding any other provision in this Agreement, the Corporation shall not be obligated under this Agreement to make any indemnification in connection with any claim made against Indemnitee:

(a)    in connection with any Proceeding charging improper personal benefit to Indemnitee, whether or not involving action in Indemnitee’s Covered Capacity, in which Indemnitee is adjudged liable on the basis that personal benefit was improperly received by Indemnitee;

(b)    for which payment has actually been received by or on behalf of Indemnitee under any insurance policy or other indemnity provision or agreement (other than this Agreement), either by the Corporation or otherwise, except with respect to any excess beyond the amount actually received under any insurance policy, contract, agreement, other indemnity provision or otherwise;

(c)    for an accounting of profits made from the purchase and sale (or sale and purchase) by Indemnitee of securities of the Corporation within the meaning of Section 16(b) of the Exchange Act or similar provisions of state statutory law or common law; or

(d)    in connection with any Proceeding (or any part of any Proceeding) initiated by Indemnitee, and not brought by way of defense, including any Proceeding (or any part of any Proceeding) initiated by Indemnitee against the Corporation or its directors, officers, employees or other indemnitees, unless (i) the Board of Directors of the Corporation authorized the Proceeding (or any part of any Proceeding) prior to its initiation or

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(ii) the Corporation otherwise provides such indemnification in its sole discretion, if permitted by applicable law.

In no event shall the Corporation be obligated to indemnify Indemnitee pursuant to this Agreement to the extent such indemnification is prohibited by applicable law.

5.    Advancement of Expenses; Defense of Claim.

(a)    Notwithstanding any provision of this Agreement to the contrary, and to the fullest extent permitted by applicable law, the Corporation shall pay for or reimburse to Indemnitee the reasonable Expenses incurred by Indemnitee in connection with any Proceeding in advance of the final disposition of the Proceeding. To request such an advance payment or reimbursement, Indemnitee must submit to the Corporation a written statement in a form reasonably acceptable to the Corporation that (i) sets forth in reasonable detail the Expenses to be advanced, (ii) contains a written affirmation of Indemnitee’s good-faith belief that Indemnitee has met the standard of conduct described in Section 33-8-510 of the 1976 Code of Laws of South Carolina, as amended, or any successor provision of applicable law, and (iii) is accompanied by an undertaking substantially in the form of Exhibit A hereto providing that Indemnitee undertakes to repay the advance to the extent that it is ultimately determined that Indemnitee did not meet the standard of conduct. All advances shall be unsecured and interest free and shall be made without regard to Indemnitee’s ability to repay the Expenses. Authorization of advancement of expenses shall be made using the procedures set forth in Section 7.

(b)    Section 5(a) shall not apply to any claim made by Indemnitee for which indemnification is excluded pursuant to Section 4.

(c)    The Corporation shall be entitled to participate at its own expense in the defense of any Proceeding to which Indemnitee is a party.

6.    Procedure For Notification And Application For Indemnification.

(a)    Indemnitee agrees to notify promptly the Corporation in writing upon being served with any summons, citation, subpoena, complaint, indictment, or document relating to any Proceeding or matter which may be subject to indemnification or advancement of Expenses covered hereunder. Additionally, Indemnitee will, to the extent reasonably feasible, keep the Corporation generally informed of and consult with the Corporation with respect to, the status and defense of any such Proceeding or matter; provided, however, that this sentence shall not apply in the event of a Proceeding initiated by Indemnitee to enforce the provisions of this Agreement. The failure of Indemnitee to so notify or keep the Corporation generally informed and to consult with the Corporation shall not relieve the Corporation of any obligation which it may have to Indemnitee under this Agreement.

(b)    Indemnitee may deliver to the Corporation a written application to indemnify Indemnitee in accordance with this Agreement. The General Counsel of the Corporation (or in the absence of the General Counsel, the Corporate Secretary of the Corporation) shall, promptly upon receipt of such a request for indemnification, advise the Board in writing that Indemnitee has requested indemnification. Such application(s) may be delivered from time to time and at such time(s) as Indemnitee deems appropriate in Indemnitee’s sole discretion.

7.    Procedure Upon Application For Indemnification Or Advancement Of Expenses.

(a)    Upon delivery of the written application by Indemnitee for indemnification pursuant to Section 6(b) or for advancement of expenses pursuant to Section 5(a), a determination, if required by applicable law, (y) that Indemnitee has met the applicable standard of conduct to permit indemnification, in the case of an application for indemnification, or (z) that the facts then known to those making the determination would not preclude indemnification, in the case of an application for advancement of expenses, shall be made in the specific case by one of the following methods, which shall be at the election of Indemnitee: (i) by a majority vote of a quorum consisting of Disinterested Directors, or if a quorum consisting of Disinterested Directors cannot be obtained, by majority vote of a committee duly designated by the Board (in which designation directors who are not

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Disinterested Directors may participate) consisting solely of two or more Disinterested Directors or (ii) by Independent Counsel in a written opinion to the Board, a copy of which shall be delivered to Indemnitee. If it is determined that Indemnitee has met the applicable standard of conduct, then indemnification of Indemnitee shall be authorized, to the fullest extent permitted by law, in the same manner as the determination of the permissibility of indemnification was made, except that if the determination was made by Independent Counsel, the authorization of indemnification and evaluation as to reasonableness of expenses must be made by those entitled to select the Independent Counsel pursuant to Section 7(b). Indemnitee shall reasonably cooperate with the person, persons or entity making such determination with respect to Indemnitee’s entitlement to indemnification, including providing to such person, persons or entity upon reasonable advance request any documentation or information which is not privileged or otherwise protected from disclosure and which is reasonably available to Indemnitee and reasonably necessary to such determination. Any costs or Expenses (including attorneys’ fees and disbursements) incurred by Indemnitee in so cooperating with the person, persons or entity making such determination shall be borne by the Corporation (irrespective of the determination as to Indemnitee’s entitlement to indemnification). All determinations and authorizations contemplated by this Section  7(a) with respect to an application for indemnification shall be made within 30 days following the delivery of the application, and payment of all authorized amounts shall be made within 10 days following authorization. The Corporation will promptly advise Indemnitee in writing with respect to any determination that Indemnitee is or is not entitled to indemnification, including a description of any reason or basis for which indemnification has been denied.

(b)    In the event the determination of the permissibility of indemnification is to be made by Independent Counsel pursuant to Section 7(a), the Independent Counsel shall be selected (i) by a majority vote of a quorum consisting of Disinterested Directors, (ii) if a quorum consisting of Disinterested Directors cannot be obtained, by majority vote of a committee duly designated by the Board (in which designation directors who are not Disinterested Directors may participate) consisting solely of two or more Disinterested Directors or (iii) if a quorum of the Board cannot be obtained under (i) and a committee cannot be designated under subdivision (ii), by majority vote of the full Board (in which selection directors who are parties may participate).

(c)    If the Corporation disputes a portion of the amounts for which indemnification is requested, the undisputed portion shall be paid and only the disputed portion withheld pending resolution of the disputes.

8.    Termination of Proceedings. The termination of any Proceeding or of any claim, issue or matter therein, by judgment, order, settlement or conviction, or upon a plea of nolocontendere or its equivalent, shall not of itself adversely affect the right of Indemnitee to indemnification or be determinative that Indemnitee did not meet the requisite standard of conduct to permit indemnification pursuant to this Agreement.

9.    Nonexclusivity; Survival of Rights; Insurance; Subrogation.

(a)    The rights of Indemnitee as provided by this Agreement (i) shall not be deemed exclusive of any other rights to which Indemnitee may at any time be entitled under applicable law, the Corporation’s articles of incorporation or bylaws, any agreement, a vote of shareholders, a resolution of directors or otherwise and (ii) shall be enforced and this Agreement shall be interpreted independently of and without reference to or limitation or constraint (whether procedural, substantive or otherwise) by any other such rights to which Indemnitee may at any time be entitled. No amendment or alteration of this Agreement or of any provision hereof shall limit or restrict any right of Indemnitee under this Agreement in respect of any action taken or omitted by such Indemnitee in Indemnitee’s Covered Capacity prior to such amendment or alteration. To the extent that a change in applicable law, whether by statute or judicial decision, permits greater indemnification or advancement rights than would be afforded currently under the Corporation’s articles of incorporation or bylaws and this Agreement, it is the intent of the parties hereto that Indemnitee shall enjoy by this Agreement the greater benefits so afforded by such change. To the extent that a change in South Carolina law, whether by statute or judicial decision, narrows or limits indemnification or advancement of Expenses so that they are less than are afforded currently under the Corporation’s articles of incorporation or bylaws and this Agreement, it is the intent of the parties hereto that such change, except to the extent required by applicable law, shall have no effect on this Agreement or the parties’ rights and obligations hereunder. No right or remedy herein conferred is intended to be exclusive of any other right or remedy, and every

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other right and remedy shall be cumulative and in addition to every other right and remedy given hereunder or under now or hereafter existing at law, in equity or otherwise. The assertion or employment of any right or remedy hereunder or otherwise, shall not prevent the concurrent assertion or employment of any other right or remedy.

(b)    The purchasing or and maintaining of insurance or the furnishing of similar protection or the making of other arrangements including, but not limited to, providing a trust fund, letter of credit, or surety bond on behalf of Indemnitee against any liability in a Covered Capacity whether or not the Corporation would have the power to indemnify Indemnitee against such liability under the provisions of this Agreement, shall not in any way limit or affect the rights and obligations of the Corporation or of Indemnitee under this Agreement except as expressly provided herein, and the execution and delivery of this Agreement by the Corporation and Indemnitee shall not in any way limit or affect the rights and obligations of the Corporation or the other party or parties thereto under any such arrangement.

(c)    To the extent that the Corporation maintains an insurance policy or policies providing liability insurance for directors, officers, partners, trustees, employees or agents of the Corporation or any other foreign or domestic corporation, partnership, joint venture, trust, employee benefit plan or other enterprise which such person serves at the request of the Corporation, Indemnitee shall be covered by such policy or policies in accordance with its or their terms to the maximum extent of the coverage available for any such director, officer, partner, trustee, employee or agent under such policy or policies. If, at the time the Corporation receives notice from any source of a Proceeding as to which Indemnitee is a party or a participant (as a witness or otherwise), the Corporation has director and officer liability insurance in effect, the Corporation shall give prompt notice of such Proceeding to the insurers in accordance with the procedures set forth in the respective policies. The Corporation shall thereafter take all necessary or desirable action to cause such insurers to pay, on behalf of Indemnitee, all amounts payable as a result of such Proceeding in accordance with the terms of such policies.

(d)    In the event of any payment under this Agreement, the Corporation shall be subrogated to the extent of such payment to all of the rights of recovery of Indemnitee, who shall execute all papers required and take all action necessary to secure such rights, including execution of such documents as are necessary to enable the Corporation to bring suit to enforce such rights.

(e)    The Corporation’s obligation to indemnify or advance Expenses hereunder to Indemnitee who is or was serving at the request of the Corporation as a director, officer, partner, trustee, employee or agent of any other foreign or domestic corporation, partnership, joint venture, trust, employee benefit plan or other enterprise shall be reduced by any amount Indemnitee has actually received as indemnification payments or advancement of expenses from such other foreign or domestic corporation, partnership, joint venture, trust, employee benefit plan or other enterprise. Notwithstanding any other provision of this Agreement to the contrary, (i) Indemnitee shall have no obligation to reduce, offset, allocate, pursue or apportion any indemnification, advancement or insurance coverage among multiple parties possessing such duties to Indemnitee prior to the Corporation’s satisfaction and performance of all its obligations under this Agreement, and (ii) the Corporation shall perform fully its obligations under this Agreement without regard to whether Indemnitee holds, may pursue or has pursued any indemnification, advancement or insurance coverage rights against any person or entity other than the Corporation.

10.    Duration of Agreement. All agreements and obligations of the Corporation contained herein shall continue during the period Indemnitee serves in a Covered Capacity continue and survive thereafter, regardless of the termination of Indemnitee’s service in a Covered Capacity, so long as Indemnitee shall be subject to any possible Proceeding (including any rights of appeal thereto and any Proceeding commenced by Indemnitee to enforce the provisions of this Agreement) by reason of serving in a Covered Capacity, whether or not Indemnitee is acting in any Covered Capacity at the time any liability or expense is incurred for which other rights exist under this Agreement.

11.    Severability. If any provision or provisions of this Agreement shall be held to be invalid, illegal or unenforceable for any reason whatsoever: (a) the validity, legality and enforceability of the remaining provisions of this Agreement (including, without limitation, each portion of any Section, paragraph or sentence of this Agreement containing any such provision held to be invalid, illegal or unenforceable, that is not itself invalid, illegal or

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unenforceable) shall not in any way be affected or impaired thereby and shall remain enforceable to the fullest extent permitted by law; (b) such provision or provisions shall be deemed reformed to the extent necessary to conform to applicable law and to give the maximum effect to the intent of the parties hereto; and (c) to the fullest extent possible, the provisions of this Agreement (including, without limitation, each portion of any Section, paragraph or sentence of this Agreement containing any such provision held to be invalid, illegal or unenforceable, that is not itself invalid, illegal or unenforceable) shall be construed so as to give effect to the intent manifested thereby.

12.    Enforcement and Binding Effect.

(a)    The Corporation expressly confirms and agrees that it has entered into this Agreement and assumed the obligations imposed on it hereby in order to encourage Indemnitee to continue to serve as a director and/or officer of the Corporation and/or one or more of the Corporation’s subsidiaries, and the Corporation acknowledges that Indemnitee is relying upon this Agreement in so serving.

(b)    Subject to Section 9(a), this Agreement constitutes the entire agreement between the parties hereto with respect to the subject matter hereof and supersedes all prior agreements and understandings, oral, written and implied, between the parties hereto with respect to the subject matter hereof.

(c)    The rights to be indemnified and to receive advancement of Expenses provided by or granted Indemnitee pursuant to this Agreement shall apply to Indemnitee’s service in a Covered Capacity prior to the date of this Agreement.

(d)    The rights to indemnification and advancement of Expenses provided by or granted pursuant to this Agreement (i) shall be binding upon, be enforceable by, and inure to the benefit of the parties hereto and their respective successors and assigns, including any direct or indirect successor by purchase, merger, consolidation, reorganization or otherwise to all or substantially all of the business or assets of the Corporation (and such successor will thereafter be deemed the “Corporation” for purposes of this Agreement); (ii) shall continue as to an Indemnitee who has ceased to serve in a Covered Capacity; and (iii) shall be enforceable by and inure to the benefit of Indemnitee and Indemnitee’s spouse, assigns, estate, heirs, devisees, executors and administrators and other legal representatives.

(e)    The Corporation shall require and cause any successor (whether direct or indirect, by purchase, merger, consolidation, reorganization or otherwise) to all, substantially all or a substantial part, of the business and/or assets of the Corporation, by written agreement in the form and substance reasonably satisfactory to Indemnitee and Indemnitee’s counsel, expressly to assume and agree to perform this Agreement in the same manner and to the same extent the Corporation would be required to perform if no such succession had taken place.

(f)    The Corporation and Indemnitee agree herein that a monetary remedy for breach of this Agreement, at some later date, may be inadequate, impracticable and difficult of proof, and further agree that such breach may cause Indemnitee irreparable harm. Accordingly, the parties hereto agree that Indemnitee may enforce this Agreement by seeking, among other things, injunctive relief and/or specific performance hereof, without any necessity of showing actual damage or irreparable harm and that by seeking injunctive relief and/or specific performance, Indemnitee shall not be precluded from seeking or obtaining any other relief to which Indemnitee may be entitled. The Corporation and Indemnitee further agree that Indemnitee shall be entitled to such specific performance and injunctive relief, including temporary restraining orders, preliminary injunctions and permanent injunctions, without the necessity of posting bonds or other undertaking in connection therewith. The Corporation acknowledges that in the absence of a waiver, a bond or undertaking may be required of Indemnitee by the South Carolina Court, and the Corporation hereby waives any such requirement of such a bond or undertaking.

13.    Modification and Waiver. No supplement, modification or amendment of this Agreement shall be binding unless executed in writing by the parties hereto. No waiver of any of the provisions of this Agreement shall be deemed or shall constitute a waiver of any other provisions of this Agreement nor shall any waiver constitute a continuing waiver.

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14.    Notices. All notices, requests, demands and other communications under this Agreement shall be in writing and shall be deemed to have been duly given (a) if delivered by hand and receipted for by the party to whom said notice or other communication shall have been directed; or (b) mailed by certified or registered mail with postage prepaid, on the third business day after the date on which it is so mailed:

(a)    If to Indemnitee, at the address indicated on the signature page of this Agreement, or such other address as Indemnitee shall provide in writing to the Corporation.

(b)    If to the Corporation to:

SCANA Corporation

MC D-308

220 Operation Way

Cayce, SC 29033

Attention: General Counsel

or to any other address as may have been furnished to Indemnitee in writing by the Corporation.

15.    Applicable Law And Consent To Jurisdiction. This Agreement and the legal relations among the parties shall be governed by, and construed and enforced in accordance with, the laws of the State of South Carolina, without regard to its conflict of laws rules. THE CORPORATION AND INDEMNITEE HEREBY IRREVOCABLY AND UNCONDITIONALLY: (A) AGREE THAT ANY ACTION OR PROCEEDING ARISING OUT OF OR IN CONNECTION WITH THIS AGREEMENT SHALL BE BROUGHT ONLY IN THE SOUTH CAROLINA COURT AND NOT IN ANY OTHER STATE OR FEDERAL COURT IN THE UNITED STATES OF AMERICA OR ANY COURT IN ANY OTHER COUNTRY; (B) CONSENT TO SUBMIT TO THE EXCLUSIVE JURISDICTION OF THE SOUTH CAROLINA COURT FOR PURPOSES OF ANY ACTION OR PROCEEDING ARISING OUT OF OR IN CONNECTION WITH THIS AGREEMENT; (C) WAIVE ANY OBJECTION TO THE LAYING OF VENUE OF ANY SUCH ACTION OR PROCEEDING IN THE SOUTH CAROLINA COURT; AND (D) WAIVE, AND AGREE NOT TO PLEAD OR TO MAKE, ANY CLAIM THAT ANY SUCH ACTION OR PROCEEDING BROUGHT IN THE SOUTH CAROLINA COURT HAS BEEN BROUGHT IN AN IMPROPER OR INCONVENIENT FORUM, OR IS SUBJECT (IN WHOLE OR IN PART) TO A JURY TRIAL.

16.    Identical Counterparts. This Agreement may be executed in one or more counterparts, each of which shall for all purposes be deemed to be an original but all of which together shall constitute one and the same Agreement. Only one such counterpart signed by the party against whom enforceability is sought needs to be produced to evidence the existence of this Agreement.

17.    Period Of Limitations. No legal action shall be brought and no cause of action shall be asserted by or in the right of the Corporation against Indemnitee, Indemnitee’s spouse, heirs, executors or personal or legal representatives after the expiration of two years from the date of accrual of such cause of action, and any claim or cause of action of the Corporation shall be extinguished and deemed released unless asserted by the timely filing of a legal action within such two-year period; provided, however, that if any shorter period of limitations is otherwise applicable to any such cause of action such shorter period shall govern.

18.    Additional Acts. If for the validation of any of the provisions in this Agreement any act, resolution, approval or other procedure is required, the Corporation undertakes to cause such act, resolution, approval or other procedure to be affected or adopted in a manner that will enable the Corporation to fulfill its obligations under this Agreement.

19.    Headings. The headings of the sections of this Agreement are inserted for convenience only and

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shall not be deemed to constitute part of this Agreement or to affect the construction thereof.

[REMAINDER OF PAGE INTENTIONALLY LEFT BLANK]

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IN WITNESS WHEREOF, the parties have caused this Agreement to be signed as of the day and year first above written.

The Corporation:    SCANA CORPORATION

By:

Name:

Title:

Indemnitee:        

Printed Name:        

Address:        

10

Exhibit A

UNDERTAKING

Reference is made to that certain Indemnification Agreement between SCANA Corporation, a South Carolina corporation (the “Corporation”), and Indemnitee dated as of ________, 20___ (the “Indemnification Agreement”).

In regard to any advancements made by the Corporation to Indemnitee pursuant to the terms of the Indemnification Agreement, Indemnitee hereby undertakes and agrees to repay to the Corporation any and all amounts so paid promptly and in any event within thirty (30) days after the disposition, including exhaustion of all appeals therefrom, of any litigation or threatened litigation on account of which advancements were made if it is determined that Indemnitee did not meet the standard of conduct described in Section 33-8-510 of the 1976 Code of Laws of South Carolina, as amended, or any successor provision of applicable law.

Indemnitee:        

Printed Name:        

Address:        

A-#PageNum#

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: August 3, 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: August 3, 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: August 3, 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: August 3, 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 June 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: August 3, 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 June 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: August 3, 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 June 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: August 3, 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 June 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: August 3, 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 $)	Jun. 30, 2012		Dec. 31, 2011
Derivative [Line Items]
Commodity and other energy management contracts designated as cash flow hedges (in DT)	31,422,638		36,427,763
Nonmonetary Notional Amount of Price Risk Derivative Instruments Not Designated as Hedging Instruments	36,094,637	[1]	41,023,563	[2]
Commodity and other energy management contracts (in DT)	67,517,275	[1]	77,451,326	[2]
Commodity and other energy management contracts not designated as hedges (in DT)	6,952,000		9,626,000
Aggregate notional amount of interest rate swaps designated as fair value hedge (in dollars)			$ 0
Aggregate notional amount of interest rate swaps designated as cash flow hedge (in dollars)	1.0		822.6
Gas Distribution
Derivative [Line Items]
Commodity and other energy management contracts designated as cash flow hedges (in DT)	0		0
Nonmonetary Notional Amount of Price Risk Derivative Instruments Not Designated as Hedging Instruments	9,520,000		9,080,000
Commodity and other energy management contracts (in DT)	9,520,000		9,080,000
Retail Gas Marketing
Derivative [Line Items]
Commodity and other energy management contracts designated as cash flow hedges (in DT)	6,573,000		6,566,000
Nonmonetary Notional Amount of Price Risk Derivative Instruments Not Designated as Hedging Instruments	0		0
Commodity and other energy management contracts (in DT)	6,573,000		6,566,000
Energy Marketing
Derivative [Line Items]
Commodity and other energy management contracts designated as cash flow hedges (in DT)	24,849,638		29,861,763
Nonmonetary Notional Amount of Price Risk Derivative Instruments Not Designated as Hedging Instruments	26,574,637	[1]	31,943,563	[2]
Commodity and other energy management contracts (in DT)	51,424,275	[1]	61,805,326	[2]
SCE&G
Derivative [Line Items]
Aggregate notional amount of interest rate swaps designated as cash flow hedge (in dollars)	$ 921,400,000		$ 471,400,000
SCE&G | Gas Distribution
Derivative [Line Items]
Nonmonetary Notional Amount of Price Risk Derivative Instruments Not Designated as Hedging Instruments			2,490,000

[1] (a) Includes an aggregate 6,952,000 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		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011
Segment Reporting Information [Line Items]
Intersegment Revenue	$ 0	$ 0	$ 0
Operating Income	171	142	409	390
Regulated and Unregulated Operating Revenue	908	1,000	2,015	2,281
Income Available to Common Shareholders of SCANA	72	56	193	184
Segment Assets	13,749		13,749		13,534
Electric Operations
Segment Reporting Information [Line Items]
Intersegment Revenue	3	2	5	4
Operating Income	164	140	291	262
Regulated and Unregulated Operating Revenue	592	616	1,137	1,174
Segment Assets	8,589		8,589		8,222
Gas Distribution
Segment Reporting Information [Line Items]
Intersegment Revenue	0	0	0
Operating Income	5	2	88	86
Regulated and Unregulated Operating Revenue	126	132	400	492
Segment Assets	2,201		2,201		2,179
Retail Gas Marketing
Segment Reporting Information [Line Items]
Intersegment Revenue	0	0	0
Regulated and Unregulated Operating Revenue	71	78	224	280
Income Available to Common Shareholders of SCANA	(3)	(3)	8	19
Segment Assets	141		141		185
Energy Marketing
Segment Reporting Information [Line Items]
Intersegment Revenue	23	52	49	97
Regulated and Unregulated Operating Revenue	118	172	250	330
Income Available to Common Shareholders of SCANA	2	1	4	2
Segment Assets	93		93		114
All Other [member]
Segment Reporting Information [Line Items]
Intersegment Revenue	103	104	209	206
Operating Income	4	3	11	8
Regulated and Unregulated Operating Revenue	10	10	21	20
Income Available to Common Shareholders of SCANA	(4)	0	1	1
Segment Assets	1,250		1,250		1,377
Adjustments/Eliminations
Segment Reporting Information [Line Items]
Intersegment Revenue	(129)	(158)	(263)	(307)
Operating Income	(2)	(3)	19	34
Regulated and Unregulated Operating Revenue	(9)	(8)	(17)	(15)
Income Available to Common Shareholders of SCANA	77	58	180	162
Segment Assets	1,475		1,475		1,457
SCE&G
Segment Reporting Information [Line Items]
Regulated Operating Revenue	661	691	1,324	1,396
Operating Income	165	137	321	289
Net Income (Loss) Attributable to Parent	76	59	143	127
Segment Assets	11,431		11,431		11,037
SCE&G | Electric Operations
Segment Reporting Information [Line Items]
Regulated Operating Revenue	594	618	1,141	1,178
Operating Income	163	140	290	262
Segment Assets	8,589		8,589		8,222
SCE&G | Gas Distribution
Segment Reporting Information [Line Items]
Regulated Operating Revenue	67	73	183	218
Operating Income	2	(2)	31	28
Segment Assets	636		636		622
SCE&G | Adjustments/Eliminations
Segment Reporting Information [Line Items]
Operating Income	0	(1)		(1)
Net Income (Loss) Attributable to Parent	76	59	143	127
Segment Assets	$ 2,206		$ 2,206		$ 2,193

XML

RATE AND OTHER REGULATORY MATTERS (Details 2) (USD $)	1 Months Ended	3 Months Ended	6 Months Ended	24 Months Ended			3 Months Ended				6 Months Ended		3 Months Ended		3 Months Ended						3 Months Ended				3 Months Ended		3 Months Ended	6 Months Ended		12 Months Ended			6 Months Ended			3 Months Ended
	Nov. 30, 2010	Jun. 30, 2012	Jun. 30, 2012	Jul. 31, 2012	Dec. 31, 2011	May 31, 2010	Jun. 30, 2012 Deferred Income Tax Charges [Member]	Dec. 31, 2011 Deferred Income Tax Charges [Member]	Jun. 30, 2012 Under-collections-electric fuel adjustment clause	Dec. 31, 2011 Under-collections-electric fuel adjustment clause	Jun. 30, 2012 Environmental remediation costs	Dec. 31, 2011 Environmental remediation costs	Jun. 30, 2012 Asset Retirement Obligation Costs [Member]	Dec. 31, 2011 Asset Retirement Obligation Costs [Member]	Jun. 30, 2012 Franchise agreements	Dec. 31, 2011 Franchise agreements	Jun. 30, 2012 Deferred employee benefit plan costs	Dec. 31, 2011 Deferred employee benefit plan costs	Jun. 30, 2012 Planned major maintenance	Dec. 31, 2011 Planned major maintenance	Jun. 30, 2012 Deferred losses on interest rate derivatives	Dec. 31, 2011 Deferred losses on interest rate derivatives	Jun. 30, 2012 Deferred pollution control costs	Dec. 31, 2011 Deferred pollution control costs	Jun. 30, 2012 Other.	Dec. 31, 2011 Other.	Jun. 30, 2012 SCE&G	Jun. 30, 2012 SCE&G	Jun. 30, 2011 SCE&G	Dec. 31, 2011 SCE&G	Jul. 31, 2011 SCE&G	Dec. 31, 2010 SCE&G	Jun. 30, 2012 SCE&G Deferred Income Tax Charges [Member]	Jun. 30, 2012 SCE&G Asset Retirement Obligation Costs [Member]	Jun. 30, 2012 SCE&G Franchise agreements	Jun. 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			$ 447,000,000
Public Utilities, Property, Plant and Equipment, Description of Plant Abandonment																												22506309
Storm Damage Reserve Cost Applied																												1,500,000	1,800,000
Public Utilities, Increase (Decrease) in Retail Natural Gas Rates Requested and Approved under RSA																												151,500,000		8.6		10.4
Public Utilities Percent Increase (Decrease) in Retail Electric Rates Requested and Approved Under BLRA																												2.50%		2.40%		2.30%
Public Utilities Increase (Decrease) in Retail Electric Rates Requested and Approved under BLRA																												56,700,000		52.8		47.3
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
Public Utilities Additional Labor Expenses for Oversight of New Units			132,000,000
Regulatory assets		1,265,000,000	1,265,000,000		1,279,000,000		243,000,000	243,000,000	0	28,000,000	30,000,000	30,000,000	320,000,000	316,000,000	38,000,000	40,000,000	387,000,000	392,000,000	0	6,000,000	163,000,000	154,000,000	32,000,000	25,000,000	52,000,000	45,000,000	1,192,000,000	1,192,000,000		1,206,000,000				0	0
Regulatory assets, expected recovery period (in years)		30					70				17		95		20						30				30								70			12
Public Utilities Base Fuel under Collected Balance Recovery Period			12																									12
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

6 Months Ended

Jun. 30, 2012

Jun. 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 six months ended June 30, 2012 and 2011 were as follows:

Millions of dollars	2012			2011
Balance at January 1,	$	3,889		$	3,702
Common stock issued	50			50
Dividends declared	(130		)	(124		)
Comprehensive income	201			177
Balance as of June 30,	$	4,010		$	3,805

SCE&G

Schedule of Capitalization, Equity [Line Items]

Schedule of Stockholders Equity [Table Text Block]

Changes in common equity during the six months ended June 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	51			—			51
Dividends declared	(103		)	(4		)	(107		)
Comprehensive income	143			6			149
Balance as of June 30, 2012	$	3,756		$	110		$	3,866
Balance at January 1, 2011	$	3,437		$	104		$	3,541
Capital contribution from parent	49			—			49
Dividends declared	(97		)	(3		)	(100		)
Comprehensive income	127			5			132
Balance as of June 30, 2011	$	3,516		$	106		$	3,622

Dividends

$ (107)

$ (100)

Contributions from parent

51

49

Stockholders' Equity Attributable to Noncontrolling Interest

110

108

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

$ 3,866

$ 3,622

$ 3,773

$ 3,541

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details) (USD $)	Jun. 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	1,000,000	1,000,000
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other energy management contracts
Assets, Fair Value Disclosure [Abstract]
Derivative Assets	1,000,000	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	1,000,000	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	28,000,000	2,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	120,000,000	158,000,000
Fair Value, Inputs, Level 2 [Member] | Commodity contracts
Assets, Fair Value Disclosure [Abstract]
Derivative Assets	2,000,000	1,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	6,000,000	13,000,000
Fair Value, Inputs, Level 2 [Member] | Other energy management contracts
Assets, Fair Value Disclosure [Abstract]
Derivative Assets	21,000,000	27,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	22,000,000	26,000,000
SCE&G | Fair Value, Inputs, Level 2 [Member] | Interest Rate Contract
Assets, Fair Value Disclosure [Abstract]
Derivative Assets	28	1
Liabilities, Fair Value Disclosure [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	$ 0	$ 77

XML

LONG-TERM AND SHORT-TERM DEBT (Details 2) (USD $) In Millions, unless otherwise specified																														3 Months Ended		3 Months Ended
	Jun. 30, 2012	Jun. 30, 2012 PSNC Energy	Jun. 30, 2012 SCE&G (including Fuel Company)	Jun. 30, 2012 Fuel Company	Jun. 30, 2012 Parent Company [Member]	Jun. 30, 2012 Wells Fargo Bank, National Association (Member)	Jun. 30, 2012 Bank of America, N.A. (Member)	Jun. 30, 2012 Morgan Stanly Bank, N.A. (Member)	Jun. 30, 2012 Branch Banking and Trust Company (Member)	Jun. 30, 2012 Credit Suisse AG, Cayman Islands Branch (Member)	Jun. 30, 2012 JPMorgan Chase Bank, N.A. (Member)	Jun. 30, 2012 Mizuho Corporate Bank, Ltd (Member)	Jun. 30, 2012 TD Bank, N.A. (Member)	Jun. 30, 2012 UBS Loan Finance LLC (Member)	Jun. 30, 2012 Deutsche Bank AG, New York Branch (Member)	Jun. 30, 2012 Union Bank, N.A. (Member)	Jun. 30, 2012 US Bank National Association (Member)	Jun. 30, 2012 SCE&G	Dec. 31, 2011 SCE&G	Jun. 30, 2012 Parent Company [Member]	Dec. 31, 2011 Parent Company [Member]	Jun. 30, 2012 Retail Gas Marketing and Energy Marketing	Dec. 31, 2011 Retail Gas Marketing and Energy Marketing	Jun. 30, 2012 SCE&G (including Fuel Company)	Dec. 31, 2011 SCE&G (including Fuel Company)	Jun. 30, 2012 SCE and G [Member]	Jun. 30, 2012 SCE and G [Member] Deutsche Bank AG, New York Branch (Member)	Jun. 30, 2012 PSNC Energy	Dec. 31, 2011 PSNC Energy	Jun. 30, 2012 First Mortgage Bonds [Member]	Jun. 30, 2012 First Mortgage Bonds [Member] SCE&G	Jun. 30, 2012 Medium Term Notes First [Member]	Jun. 30, 2012 Medium Term Notes First [Member] SCE and G [Member]	Jun. 30, 2012 Medium-term Notes [Member]
Debt Instrument [Line Items]
Due to Affiliate, Current																		$ 128.0	$ 136.0			$ 10.0	$ 13.2
Debt Instruments [Abstract]
Debt Instrument, Increase, Additional Borrowings																														250		250	250
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																										67.8
Lines of credit:
Line of Credit Facility, Maximum Borrowing Capacity	1,500	100	1,100	400	300															300	300				1,100	1,100		100	100
Commercial Paper																				84	131			586	512			0	10
Commercial paper, weighted average interest rate (as a percent)																				0.88%	0.63%			0.49%	0.56%			0.00%	0.57%
Letters of credit supported by LOC																				3.0	3.0			0	0			0	0
Line of Credit Facility, Remaining Borrowing Capacity																				213	166			514	588			100	90
LOC advances																				$ 0	$ 0			$ 0	$ 0			$ 0	$ 0
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank						10.00%	10.00%	10.00%	8.00%	8.00%	8.00%	8.00%	8.00%	8.00%	5.30%	5.30%	5.30%										5.30%
Number of other banks (in entities)	3

XML

AFFILIATED TRANSACTIONS - SCEG AFFILIATED TRANSACTIONS -SCEG (Details) (USD $) In Millions, unless otherwise specified				6 Months Ended	12 Months Ended		6 Months Ended
	Jun. 30, 2012	Dec. 31, 2011	Jun. 30, 2012 Canadys Refined Coal LLC [Member]	Jun. 30, 2012 Cope Refined Coal LLC [Member]	Dec. 31, 2011 Cope Refined Coal LLC [Member]	Jun. 30, 2011 Cope Refined Coal LLC [Member]	Jun. 30, 2012 CGT [Member]	Jun. 30, 2011 CGT [Member]	Jun. 30, 2012 Retail Gas Marketing and Energy Marketing	Jun. 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				$ 46.9	$ 53.3		$ 18.5	$ 15.8
Due to Affiliate, Current							2.6	2.5	10.0		13.2
Equity Method Investment, Ownership Percentage			40.00%	10.00%
Increase (Decrease) Due from Affiliates				6.4	8.5
Cost of Natural Gas Purchases									48.8	96.7
Equity Method Investment, Dividends or Distributions				6.4	8.6
Energy Related Inventory, Coal				46.6		53.1
Related Party Transaction, Due from (to) Related Party, Current	70.1	58.5
Accounts Payable, Related Parties, Current	$ 28	$ 43

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parentheticals) (USD $)	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
Cash paid for interest, capitalized interest	$ 4	$ 5
SCE&G
Cash paid for interest, capitalized interest	$ 4	$ 4

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details 2) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Carrying Amount
Financial instruments for which the carrying amount may not equal estimated fair value
Long-term debt	$ 4,883.6	$ 4,653.0
Estimated Fair Value
Financial instruments for which the carrying amount may not equal estimated fair value
Long-term debt	5,835.0	5,479.2
SCE&G | Carrying Amount
Financial instruments for which the carrying amount may not equal estimated fair value
Long-term debt	3,482.4	3,241.5
SCE&G | Estimated Fair Value
Financial instruments for which the carrying amount may not equal estimated fair value
Long-term debt	$ 4,282.1	$ 3,920.3

XML

EMPLOYEE BENEFIT PLANS (Tables)

6 Months Ended

Jun. 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 June 30,
Service cost	$	4.9		$	4.6		$	1.2	$	1.1
Interest cost	10.6			11.1			3.0		3.0
Expected return on assets	(14.8		)	(16.2		)	—		—
Prior service cost amortization	1.8			1.8			0.3		0.3
Transition obligation amortization	—			—			0.1		0.2
Amortization of actuarial loss	4.6			3.0			0.2		0.1
Net periodic benefit cost	$	7.1		$	4.3		$	4.8	$	4.7
Six months ended June 30,
Service cost	$	9.7		$	9.2		$	2.5	$	2.2
Interest cost	21.3			22.2			6.0		6.0
Expected return on assets	(29.6		)	(32.4		)	—		—
Prior service cost amortization	3.5			3.6			0.5		0.6
Transition obligation amortization	—			—			0.3		0.4
Amortization of actuarial loss	9.3			6.0			0.4		0.2
Net periodic benefit cost	$	14.2		$	8.6		$	9.7	$	9.4

SCE&G

Pension and Other Postretirement Benefit Plans

Schedule of Net Benefit Costs [Table Text Block]

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 June 30,
Service cost	$	3.8		$	3.7		$	1.0	$	0.9
Interest cost	9.1			9.5			2.3		2.3
Expected return on assets	(12.6		)	(13.7		)	—		—
Prior service cost amortization	1.5			1.5			0.2		0.2
Amortization of actuarial loss	4.0			2.5			0.1		0.1
Net periodic benefit cost	$	5.8		$	3.5		$	3.6	$	3.5
Six months ended June 30,
Service cost	$	7.7		$	7.4		$	2.0	$	1.8
Interest cost	18.2			18.9			4.7		4.7
Expected return on assets	(25.2		)	(27.5		)	—		—
Prior service cost amortization	2.9			3.0			0.4		0.4
Amortization of actuarial loss	8.0			5.1			0.2		0.1
Net periodic benefit cost	$	11.6		$	6.9		$	7.3	$	7.0

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FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Tables)

6 Months Ended

Jun. 30, 2012

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

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

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

	June 30, 2012				December 31, 2011
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	4,883.6	$	5,835.0	$	4,653.0	$	5,479.2

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 June 30, 2012
Assets -	Available for sale securities	$	8	—
	Interest rate contracts	—		$	28
	Commodity contracts	1		2
	Energy management contracts	—		21
Liabilities -	Interest rate contracts	—		120
	Commodity contracts	1		6
	Energy management contracts	1		22
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

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		June 30, 2012	December 31, 2011
Assets -	Interest rate contracts	$28	$1
Liabilities-	Interest rate contracts	87	77

XML

EMPLOYEE BENEFIT PLANS (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Components of Net Periodic Benefit Cost
Pension Costs Related to Retail Electric Operations and Natural Gas Operations Deferred as Regulatory Assets	$ 3,700,000	$ 2,300,000	$ 7,400,000	$ 4,600,000
Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	4,900,000	4,600,000	9,700,000	9,200,000
Interest cost	10,600,000	11,100,000	21,300,000	22,200,000
Expected return on assets	(14,800,000)	(16,200,000)	(29,600,000)	(32,400,000)
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	1,800,000	3,500,000	3,600,000
Defined Benefit Plan, Amortization of Transition Obligations (Assets)	0	0	0	0
Defined Benefit Plan, Actuarial Net (Gains) Losses	4,600,000	3,000,000	9,300,000	6,000,000
Defined Benefit Plan, Net Periodic Benefit Cost	7,100,000	4,300,000	14,200,000	8,600,000
Other Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	1,200,000	1,100,000	2,500,000	2,200,000
Interest cost	3,000,000	3,000,000	6,000,000	6,000,000
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	300,000	300,000	500,000	600,000
Defined Benefit Plan, Amortization of Transition Obligations (Assets)	100,000	200,000	300,000	400,000
Defined Benefit Plan, Actuarial Net (Gains) Losses	200,000	100,000	400,000	200,000
Defined Benefit Plan, Net Periodic Benefit Cost	4,800,000	4,700,000	9,700,000	9,400,000
SCE&G
Pension and Other Postretirement Benefit Plans
Environmental Remediation Costs Recognized in Regulatory Assets	24,300,000		24,300,000
Components of Net Periodic Benefit Cost
Pension Costs Related to Retail Electric Operations and Natural Gas Operations Deferred as Regulatory Assets		2,300,000	7,400,000	4,600,000
SCE&G | Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	3.8	3.7	7.7	7.4
Interest cost	9.1	9.5	18.2	18.9
Expected return on assets	12.6	13.7	25.2	27.5
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	(1.5)	(1.5)	(2.9)	(3.0)
Defined Benefit Plan, Actuarial Net (Gains) Losses	4.0	2.5	8.0	5.1
SCE&G | Other Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	1.0	0.9	2.0	1.8
Interest cost	2.3	2.3	4.7	4.7
Expected return on assets	0.0	0.0	0.0	0.0
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	(0.2)	(0.2)	(0.4)	(0.4)
Defined Benefit Plan, Actuarial Net (Gains) Losses	$ 0.1	$ 0.1	$ 0.2	$ 0.1

XML

SEGMENT OF BUSINESS INFORMATION (Tables)

6 Months Ended

Jun. 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 June 30, 2012
Electric Operations	$	592		$	3		$	164		n/a
Gas Distribution	126			—			5			n/a
Retail Gas Marketing	71			—			—			$	(3	)
Energy Marketing	118			23			—			2
All Other	10			103			4			(4		)
Adjustments/Eliminations	(9		)	(129		)	(2		)	77
Consolidated Total	$	908		—			$	171		$	72
Six Months Ended June 30, 2012
Electric Operations	$	1,137		$	5		$	291		n/a
Gas Distribution	400			—			88			n/a
Retail Gas Marketing	224			—			n/a			$	8
Energy Marketing	250			49			n/a			4
All Other	21			209			11			1
Adjustments/Eliminations	(17		)	(263		)	19			180
Consolidated Total	$	2,015		—			$	409		$	193
Three Months Ended June 30, 2011
Electric Operations	$	616		$	2		$	140		n/a
Gas Distribution	132			—			2			n/a
Retail Gas Marketing	78			—			n/a			$	(3	)
Energy Marketing	172			52			n/a			1
All Other	10			104			3			—
Adjustments/Eliminations	(8		)	(158		)	(3		)	58
Consolidated Total	$	1,000		—			$	142		$	56

Six Months Ended June 30, 2011
Electric Operations	$	1,174		$	4		$	262	n/a
Gas Distribution	492			—			86		n/a
Retail Gas Marketing	280			—			n/a		$	19
Energy Marketing	330			97			n/a		2
All Other	20			206			8		1
Adjustments/Eliminations	(15		)	(307		)	34		162
Consolidated Total	$	2,281		—			$	390	$	184

	June 30,		December 31,
Segment Assets	2012		2011
Electric Operations	$	8,589	$	8,222
Gas Distribution	2,201		2,179
Retail Gas Marketing	141		185
Energy Marketing	93		114
All Other	1,250		1,377
Adjustments/Eliminations	1,475		1,457
Consolidated Total	$	13,749	$	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 June 30, 2012
Electric Operations	$	594	$	163	n/a
Gas Distribution	67		2		n/a
Adjustments/Eliminations	—		—		$	76
Consolidated Total	$	661	$	165	$	76
Six Months Ended June 30, 2012
Electric Operations	$	1,141	$	290	n/a
Gas Distribution	183		31		n/a
Adjustments/Eliminations	—		—		$	143
Consolidated Total	$	1,324	$	321	$	143

Three Months Ended June 30, 2011
Electric Operations	$	618	$	140		n/a
Gas Distribution	73		(2		)	n/a
Adjustments/Eliminations	—		(1		)	$	59
Consolidated Total	$	691	$	137		$	59
Six Months Ended June 30, 2011
Electric Operations	$	1,178	$	262		n/a
Gas Distribution	218		28			n/a
Adjustments/Eliminations	—		(1		)	$	127
Consolidated Total	$	1,396	$	289		$	127

	June 30,		December 31,
Segment Assets	2012		2011
Electric Operations	$	8,589	$	8,222
Gas Distribution	636		622
Adjustments/Eliminations	2,206		2,193
Consolidated Total	$	11,431	$	11,037

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 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)	41.00%		41.00%		45.00%
Natural gas inventory, carrying amount	$ 14.6		$ 14.6		$ 28.7
Property, Plant and Equipment, Net	307		307		305
Earnings Per Share
Weighted Average Shares Outstanding - Basic	130.9	128.5	130.6	128.2
Incremental Common Shares Attributable to Share-based Payment Arrangements and Equity Forward Agreements	2.2	1.2	2.1	1.2
Weighted Average Number of Shares Outstanding, Diluted	133.1	129.7	132.7	129.4
SCE&G
Significant Accounting Policies
Power Generation Capacity Megawatts	1,117		1,117
Asset Management and Supply Service Agreements
Property, Plant and Equipment, Net	57		57		52
Genco
Significant Accounting Policies
Power Generation Capacity Megawatts	605		605
Asset Management and Supply Service Agreements
Property, Plant and Equipment, Net	$ 485		$ 485

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
Cash Flows From Operating Activities:
Income Available to Common Shareholders of SCANA	$ 193	$ 184
Adjustments to reconcile net income to net cash provided from operating activities:
Earnings from equity method investments, net of distributions	0	(1)
Deferred income taxes, net	65	45
Depreciation and amortization	183	173
Amortization of nuclear fuel	26	14
Allowance for equity funds used during construction	(7)	(8)
Cash provided (used) by changes in certain assets and liabilities:
Receivables	77	210
Inventories	(25)	8
Prepayments and other	17	57
Regulatory liabilities	28	(6)
Accounts payable	(32)	(93)
Taxes accrued	(47)	(63)
Interest accrued	4	2
Regulatory assets	20	(28)
Changes in other assets	(13)	(12)
Changes in other liabilities	(50)	(59)
Net Cash Provided From Operating Activities	439	425
Cash Flows From Investing Activities:
Property additions and construction expenditures	(591)	(477)
Proceeds from investments (including derivative collateral posted)	237	10
Purchase of investments (including derivative collateral posted)	(211)	(13)
Payments for (Proceeds from) Hedge, Investing Activities	13	0
Payments for interest rate contract settlements	(51)	(61)
Net Cash Used in Investing Activities	(603)	(541)
Cash Flows From Financing Activities:
Proceeds from Issuance of Common Stock	50	50
Proceeds from issuance of long-term debt	494	796
Repayments of Long-term Debt	(270)	(623)
Dividends	(128)	(122)
Short-term borrowings, net	17	126
Net Cash Provided From Financing Activities	163	227
Net (Decrease) Increase in Cash and Cash Equivalents	(1)	111
Cash and Cash Equivalents, January 1	29	55
Cash and Cash Equivalents, March 31	28	166
Supplemental Cash Flow Information:
Cash paid for-Interest (net of capitalized interest of $2 and $2)	141	134
Cash paid for-Income taxes	3	0
Noncash Investing and Financing Activities:
Accrued construction expenditures	61	125
Capital Lease Obligations Incurred	2	2
SCE&G
Cash Flows From Operating Activities:
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	149	132
Adjustments to reconcile net income to net cash provided from operating activities:
Losses from equity method investments	2	1
Deferred income taxes, net	56	36
Depreciation and amortization	147	142
Amortization of nuclear fuel	26	14
Allowance for equity funds used during construction	(7)	(8)
Cash provided (used) by changes in certain assets and liabilities:
Receivables	3	63
Inventories	(50)	3
Prepayments and other	(74)	43
Regulatory liabilities	29	(4)
Accounts payable	(5)	(46)
Taxes accrued	(11)	(59)
Interest accrued	5	4
Regulatory assets	20	(30)
Changes in other assets	24	(8)
Changes in other liabilities	(45)	(46)
Net Cash Provided From Operating Activities	269	237
Cash Flows From Investing Activities:
Property additions and construction expenditures	(544)	(425)
Proceeds from investments (including derivative collateral posted)	98	4
Purchase of investments (including derivative collateral posted)	(121)	(3)
Payments for (Proceeds from) Hedge, Investing Activities	13	0
Payments for interest rate contract settlements	0	(31)
Net Cash Used in Investing Activities	(554)	(455)
Cash Flows From Financing Activities:
Proceeds from issuance of long-term debt	248	349
Repayments of Long-term Debt	(10)	(164)
Dividends	(92)	(104)
Contributions from parent	51	49
Short-term borrowings, net	74	94
Short-term borrowings- affiliate,net	12	(9)
Net Cash Provided From Financing Activities	283	215
Net (Decrease) Increase in Cash and Cash Equivalents	(2)	(3)
Cash and Cash Equivalents, January 1	16	31
Cash and Cash Equivalents, March 31	14	28
Supplemental Cash Flow Information:
Cash paid for-Interest (net of capitalized interest of $2 and $2)	92	87
Cash paid for-Income taxes	0	0
Noncash Investing and Financing Activities:
Accrued construction expenditures	51	116
Capital Lease Obligations Incurred	$ 2	$ 2

XML

RATE AND OTHER REGULATORY MATTERS (Details) (USD $)	1 Months Ended	3 Months Ended	6 Months Ended	12 Months Ended	3 Months Ended		6 Months Ended	12 Months Ended			24 Months Ended
	Nov. 30, 2010	Jun. 30, 2012	Jun. 30, 2012	Dec. 31, 2011	Jun. 30, 2012 SCE&G	Jun. 30, 2011 SCE&G	Jun. 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			$ 447,000,000
Public Utilities, Property, Plant and Equipment, Description of Plant Abandonment							22506309
Amount Recovered Through Electric Rates to Offset Deferred Pollution, Control Costs					9,200,000		9,200,000
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, 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							2.50%	2.40%		2.30%
Increase (decrease) in retail electric rate requested under the BLRA							56,700,000	52.8		47.3
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	$ 8.6		$ 10.4
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	Jun. 30, 2012		Dec. 31, 2011
Derivatives designated as hedging instruments
Derivative [Line Items]
Asset Derivatives Fair Value	$ 32		$ 3	[1]
Liability Derivatives Fair Value	126		172
Derivatives designated as hedging instruments | Interest Rate Contract | Prepayments and other
Derivative [Line Items]
Asset Derivatives Fair Value	20		2
Derivatives designated as hedging instruments | Interest Rate Contract | Other deferred debits and other assets
Derivative [Line Items]
Asset Derivatives Fair Value	8
Derivatives designated as hedging instruments | Interest Rate Contract | Other current liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	79		55
Derivatives designated as hedging instruments | Interest Rate Contract | Other deferred credits and other liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	41		103
Derivatives designated as hedging instruments | Commodity contracts | Prepayments and other
Derivative [Line Items]
Asset Derivatives Fair Value	2
Liability Derivatives Fair Value			1
Derivatives designated as hedging instruments | Commodity contracts | Other current liabilities
Derivative [Line Items]
Asset Derivatives Fair Value	2		1	[1]
Liability Derivatives Fair Value	4		10
Derivatives designated as hedging instruments | Commodity contracts | Other deferred credits and other liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	2		3
Derivatives not designated as hedging instruments
Derivative [Line Items]
Asset Derivatives Fair Value	21		27
Liability Derivatives Fair Value	21		25
Derivatives not designated as hedging instruments | Other Energy Management Contract [Member] | Prepayments and other
Derivative [Line Items]
Asset Derivatives Fair Value	11		17
Liability Derivatives Fair Value	2		3
Derivatives not designated as hedging instruments | Other Energy Management Contract [Member] | Other deferred debits and other assets
Derivative [Line Items]
Asset Derivatives Fair Value	10		10
Derivatives not designated as hedging instruments | Other Energy Management Contract [Member] | Other current liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	10		13
Derivatives not designated as hedging instruments | Other Energy Management Contract [Member] | Other deferred credits and other liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	9		9
SCE&G | Derivatives designated as hedging instruments
Derivative [Line Items]
Asset Derivatives Fair Value	28	[1]	1	[1]
Liability Derivatives Fair Value	87		77
SCE&G | Derivatives designated as hedging instruments | Interest Rate Contract | Prepayments and other
Derivative [Line Items]
Asset Derivatives Fair Value	20		1
Liability Derivatives Fair Value	75
SCE&G | Derivatives designated as hedging instruments | Interest Rate Contract | Other deferred debits and other assets
Derivative [Line Items]
Asset Derivatives Fair Value	8
SCE&G | Derivatives designated as hedging instruments | Interest Rate Contract | Other current liabilities
Derivative [Line Items]
Liability Derivatives Fair Value			2
SCE&G | Derivatives designated as hedging instruments | Interest Rate Contract | 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	Jun. 30, 2012	Dec. 31, 2011
Assets
Utility Plant In Service	$ 11,472	$ 12,000
Accumulated Depreciation and Amortization	(3,700)	(3,836)
Construction Work in Progress	1,790	1,482
Plant to be Retired, Net	447	0
Nuclear Fuel, Net of Accumulated Amortization	173	171
Goodwill, Net of Writedown of $230	230	230
Utility Plant, Net	10,412	10,047
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	307	305
Assets held in trust, net-nuclear decommissioning	90	84
Other investments	85	87
Nonutility Property and Investments, Net	482	476
Current Assets:
Cash and cash equivalents	28	29
Receivables, net of allowance for uncollectible accounts	665	756
Inventories (at average cost):
Fuel	310	313
Materials and supplies	131	129
Emission allowances	2	2
Prepayments and other	214	236
Deferred income taxes	17	26
Total Current Assets	1,367	1,491
Deferred Debits and Other Assets:
Regulatory assets	1,265.0	1,279.0
Other	223	241
Total Deferred Debits and Other Assets	1,488	1,520
Total	13,749	13,534
Capitalization and Liabilities
Common equity	4,010	3,889
Long-Term Debt, Net	4,707	4,622
Total Capitalization	8,717	8,511
Current Liabilities:
Short-term borrowings	670	653
Current portion of long-term debt	176	31
Accounts payable	251	374
Customer deposits and customer prepayments	103	103
Taxes accrued	107	154
Interest accrued	78	74
Dividends declared	65	63
Derivative financial instruments	93	77
Other	79	113
Total Current Liabilities	1,622	1,642
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,595	1,533
Deferred investment tax credits	38	40
Asset retirement obligations	483	474
Pension and other postretirement benefits	296	291
Regulatory liabilities	835	778
Other	163	265
Total Deferred Credits and Other Liabilities	3,410	3,381
Commitments and Contingencies (Note 9)	0	0
Total	13,749	13,534
SCE&G
Assets
Utility Plant In Service	9,763	10,312
Accumulated Depreciation and Amortization	(3,220)	(3,367)
Construction Work in Progress	1,764	1,472
Plant to be Retired, Net	447	0
Nuclear Fuel, Net of Accumulated Amortization	174	171
Utility Plant, Net	8,928	8,588
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	57	52
Assets held in trust, net-nuclear decommissioning	90	84
Other investments	3	2
Nonutility Property and Investments, Net	150	138
Current Assets:
Cash and cash equivalents	14	16
Receivables, net of allowance for uncollectible accounts	467	482
Due from Affiliate, Current	7	9
Inventories (at average cost):
Fuel	219	196
Materials and supplies	122	120
Emission allowances	2	2
Prepayments and other	166	82
Deferred income taxes	5	8
Total Current Assets	1,002	915
Deferred Debits and Other Assets:
Regulatory assets	1,192.0	1,206.0
Other	159	190
Total Deferred Debits and Other Assets	1,351	1,396
Total	11,431	11,037
Capitalization and Liabilities
Common equity	3,756	3,665
Stockholders' Equity Attributable to Noncontrolling Interest	110	108
Long-Term Debt, Net	3,314	3,222
Total Capitalization	7,180	6,995
Current Liabilities:
Short-term borrowings	586	512
Current portion of long-term debt	169	19
Accounts payable	154	231
Due to Affiliate, Current	128.0	136.0
Customer deposits and customer prepayments	54	54
Taxes accrued	139	150
Interest accrued	59	54
Dividends declared	54	39
Derivative financial instruments	75	2
Other	38	61
Total Current Liabilities	1,456	1,258
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,424	1,371
Deferred investment tax credits	38	40
Asset retirement obligations	458	449
Pension and other postretirement benefits	181	179
Regulatory liabilities	625	575
Other	69	170
Total Deferred Credits and Other Liabilities	2,795	2,784
Commitments and Contingencies (Note 9)	0	0
Total	$ 11,431	$ 11,037

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COMMITMENTS AND CONTINGENCIES (Details) (USD $)	1 Months Ended	3 Months Ended	6 Months Ended			3 Months Ended	6 Months Ended	12 Months Ended		3 Months Ended
	Nov. 30, 2010	Jun. 30, 2012	Jun. 30, 2012	Dec. 31, 2011	May 31, 2010	Jun. 30, 2012 SCE&G	Jun. 30, 2012 SCE&G	Dec. 31, 2011 SCE&G	Dec. 31, 2005 SCE&G	Jun. 30, 2012 PSNC Energy	Jun. 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
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
Number of MGP decommissioned sites that contain residues of by-product chemicals						4
Additional costs to be incurred for remediation						7,900,000
Deferred costs, net of costs previously recovered through rates and insurance settlements included in regulatory assets						24,300,000	24,300,000
Number of MGP sites that require environmental clean-up										5
Regulatory assets		1,265,000,000	1,265,000,000	1,279,000,000		1,192,000,000	1,192,000,000	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
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
Public Utilities Additional Labor Expenses for Oversight of New Units			$ 132,000,000

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012		Jun. 30, 2011
Other Comprehensive Income, net of tax:
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax	$ 1	$ 0	$ 1		$ 0
Net Income (Loss) Attributable to Parent [Abstract]
Income Available to Common Shareholders	72	56	193		184
Other Comprehensive Income (Loss)
Unrealized gains (losses) on cash flow hedging activities arising during period	(3)	(15)	(7)		(13)
Losses on cash flow hedging activities reclassified to net income	4	1	14		6
Other Comprehensive Income	2	(14)	8		(7)
Total Comprehensive Income (Loss)	74	42	201	[1]	177	[1]
SCE&G
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	78	61	149		132
Other Comprehensive Income, net of tax:
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	78	61	149		132
Other Comprehensive Income (Loss)
Total Comprehensive Income (Loss)			149		132
Genco
Other Comprehensive Income, net of tax:
Less comprehensive income attributable to noncontrolling interest	(2)	(2)	(6)		(5)
Other Comprehensive Income (Loss)
Total Comprehensive Income (Loss)			6		5
SCE&G (including Fuel Company)
Other Comprehensive Income (Loss)
Total Comprehensive Income (Loss)	$ 76	$ 59	$ 143		$ 127

[1] (1) Accumulated other comprehensive loss totaled $86.0 million as of June 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		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012		Jun. 30, 2011		Dec. 31, 2011	Dec. 31, 2010	May 31, 2010
Schedule of Capitalization, Equity [Line Items]
Common Stock, Shares Authorized	200		200				200
COMMON EQUITY [Abstract]
Common Shareholders' Equity	$ 4,010		$ 4,010				$ 3,889
Forward Contract Indexed to Issuer's Equity, Indexed Shares									6.6
Dividends declared			(130)		(124)
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	74	42	201	[1]	177	[1]
Common Stock, Shares, Outstanding	131.0		131.0				129.9
Losses recognized on cash flow hedges, net of tax	(4)	(1)	(14)		(6)
Common stock issued			50		50
Common Stockholders' Equity		3,805			3,805			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	110		110				108
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	3,866	3,622	3,866		3,622		3,773	3,541
Contributions from parent			51		49
Dividends			(107)		(100)
Comprehensive Income (Loss), Net of Tax, Attributable to Parent			149		132
Common Stock, Shares, Outstanding	40.3		40.3
SCE&G (including Fuel Company)
COMMON EQUITY [Abstract]
Contributions from parent			51		49
Dividends			(103)		(97)
Common Shareholders' Equity	3,756	3,516	3,756		3,516		3,665	3,437
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	76	59	143		127
Genco
COMMON EQUITY [Abstract]
Stockholders' Equity Attributable to Noncontrolling Interest	110	106	110		106		108	104
Contributions from parent			0		0
Dividends			(4)		(3)
Comprehensive Income (Loss), Net of Tax, Attributable to Parent			$ 6		$ 5

[1] (1) Accumulated other comprehensive loss totaled $86.0 million as of June 30, 2012 and $93.8 million as of December 31, 2011.

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INCOME TAXES Income Taxes (Policies)

6 Months Ended

Jun. 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 $) In Millions, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 1,500
Long-term Debt, Current Maturities	176	31
Long- Term Debt Noncurrent including Derivative Liabilities	4,707	4,622
SCE&G
Debt Instrument [Line Items]
Long-term Debt, Current Maturities	169	19
Long- Term Debt Noncurrent including Derivative Liabilities	$ 3,314	$ 3,222
First Mortgage Bonds [Member] | SCE&G
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.35%

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RATE AND OTHER REGULATORY MATTERS (Tables)

6 Months Ended

Jun. 30, 2012

Regulatory Assets:

Schedule of Regulatory Assets [Table Text Block]

Millions of dollars	June 30, 2012		December 31, 2011
Regulatory Assets:
Accumulated deferred income taxes	$	243	$	243
Under-collections - electric fuel adjustment clause	—		28
Environmental remediation costs	30		30
AROs and related funding	320		316
Franchise agreements	38		40
Deferred employee benefit plan costs	387		392
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	163		154
Deferred pollution control costs	32		25
Other	52		45
Total Regulatory Assets	$	1,265	$	1,279

Schedule of Regulatory Liabilities [Table Text Block]

Regulatory Liabilities:
Accumulated deferred income taxes	$	21	$	23
Asset removal costs	680		662
Storm damage reserve	31		32
Monetization of bankruptcy claim	33		34
Deferred gains on interest rate derivatives	65		24
Planned major maintenance	5		—
Other	—		3
Total Regulatory Liabilities	$	835	$	778

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

Year	Increase	Amount (Millions)
2011	2.4%	$52.8
2010	2.3%	$47.3

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

Year	Action			Amount (Millions)
2011	2.1	%	Increase	$8.6
2010	2.1	%	Decrease	$10.4

SCE&G

Regulatory Assets:

Schedule of Regulatory Assets [Table Text Block]

Millions of dollars	June 30, 2012		December 31, 2011
Regulatory Assets:
Accumulated deferred income taxes	$	238	$	238
Under collections – electric fuel adjustment clause	—		28
Environmental remediation costs	25		25
AROs and related funding	304		301
Franchise agreements	38		40
Deferred employee benefit plan costs	344		348
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	163		154
Deferred pollution control costs	32		25
Other	48		41
Total Regulatory Assets	$	1,192	$	1,206

Schedule of Regulatory Liabilities [Table Text Block]

Regulatory Liabilities:
Accumulated deferred income taxes	$	21	$	23
Asset removal costs	503		493
Storm damage reserve	31		32
Deferred gains on interest rate derivatives	65		24
Planned major maintenance	5		—
Other	—		3
Total Regulatory Liabilities	$	625	$	575

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

years:

Year	Increase	Amount (Millions)
2011	2.4%	$52.8
2010	2.3%	$47.3

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

e following years:

Year	Action			Amount (Millions)
2011	2.1	%	Increase	$8.6
2010	2.1	%	Decrease	$10.4

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	$ 2	$ 9	$ 4	$ 8
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Tax	2	0	9	4
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	86.0		86.0		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	Jun. 30, 2012	Dec. 31, 2011
Utility Plant, Net	$ 10,412	$ 10,047
Total Current Assets	1,367	1,491
Total Deferred Debits and Other Assets	1,488	1,520
Goodwill, Writedown	230	230
Nonutility property, accumulated depreciation	138	131
Receivables, net of allowance for uncollectible accounts	5	6
SCE&G
Utility Plant, Net	8,928	8,588
Total Current Assets	1,002	915
Total Deferred Debits and Other Assets	1,351	1,396
Receivables, net of allowance for uncollectible accounts	1	3
VIEs | SCE&G
Utility Plant, Net	658	662
Total Current Assets	231	193
Total Deferred Debits and Other Assets	$ 64	$ 61

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EMPLOYEE BENEFIT PLANS

6 Months Ended

Jun. 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 June 30,
Service cost	$	4.9		$	4.6		$	1.2	$	1.1
Interest cost	10.6			11.1			3.0		3.0
Expected return on assets	(14.8		)	(16.2		)	—		—
Prior service cost amortization	1.8			1.8			0.3		0.3
Transition obligation amortization	—			—			0.1		0.2
Amortization of actuarial loss	4.6			3.0			0.2		0.1
Net periodic benefit cost	$	7.1		$	4.3		$	4.8	$	4.7
Six months ended June 30,
Service cost	$	9.7		$	9.2		$	2.5	$	2.2
Interest cost	21.3			22.2			6.0		6.0
Expected return on assets	(29.6		)	(32.4		)	—		—
Prior service cost amortization	3.5			3.6			0.5		0.6
Transition obligation amortization	—			—			0.3		0.4
Amortization of actuarial loss	9.3			6.0			0.4		0.2
Net periodic benefit cost	$	14.2		$	8.6		$	9.7	$	9.4

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 $3.7 million and $7.4 million were deferred for the three and six months ended June 30, 2012, respectively. Costs totaling $2.3 million and $4.6 million were deferred for the corresponding periods in 2011.

SCE&G

Pension and Other Postretirement Benefit Plans

EMPLOYEE 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 June 30,
Service cost	$	3.8		$	3.7		$	1.0	$	0.9
Interest cost	9.1			9.5			2.3		2.3
Expected return on assets	(12.6		)	(13.7		)	—		—
Prior service cost amortization	1.5			1.5			0.2		0.2
Amortization of actuarial loss	4.0			2.5			0.1		0.1
Net periodic benefit cost	$	5.8		$	3.5		$	3.6	$	3.5
Six months ended June 30,
Service cost	$	7.7		$	7.4		$	2.0	$	1.8
Interest cost	18.2			18.9			4.7		4.7
Expected return on assets	(25.2		)	(27.5		)	—		—
Prior service cost amortization	2.9			3.0			0.4		0.4
Amortization of actuarial loss	8.0			5.1			0.2		0.1
Net periodic benefit cost	$	11.6		$	6.9		$	7.3	$	7.0

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 $3.7 million and $7.4 million were deferred for the three and six months ended June 30, 2012, respectively. Costs totaling $2.3 million and $4.6 million were deferred for the corresponding periods in 2011.

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Document and Entity Information	6 Months Ended
	Jun. 30, 2012	Jul. 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	Jun. 30, 2012
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding		131,299,288
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	Jun. 30, 2012
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding		40,296,147

XML

COMMITMENTS AND CONTINGENCIES

6 Months Ended

Jun. 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.  EPA's proposed rule covers only GHGs from new sources.  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 replaces CAIR and the Clean Air Transport Rule proposed in July 2010 and is aimed at addressing power plant emissions that may contribute to air pollution in other states.  The rule requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide.  On December 30, 2011, the United States Court of Appeals for the District of Columbia issued an order staying CSAPR and reinstating CAIR pending resolution of an appeal of CSAPR. Air quality control installations that SCE&G and GENCO have already completed should assist the Company in complying with CSAPR and the reinstated CAIR.  The Company will continue to pursue strategies to comply with all applicable environmental regulations.  Any costs incurred to comply with CAIR, CSAPR, or other rules issued by the EPA in the future 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 things.

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 these sites will continue until 2015 and will cost an additional $7.9 million, which is accrued in Other within Deferred Credits and Other Liabilities on the consolidated balance sheet.  SCE&G expects to recover any cost arising from the remediation of MGP sites through rates and insurance settlements.  At June 30, 2012, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $24.3 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 June 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 to be 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, has 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 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 the 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) in 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 modules for the New Units and unanticipated rock conditions at the site.  A public hearing on this petition is set to begin on September 11, 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.  EPA's proposed rule covers only GHGs from new sources.  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 replaces CAIR and the Clean Air Transport Rule proposed in July 2010 and is aimed at addressing power plant emissions that may contribute to air pollution in other states.  The rule requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide.  On December 30, 2011, the United States Court of Appeals for the District of Columbia issued an order staying CSAPR and reinstating CAIR pending resolution of an appeal of CSAPR. Air quality control installations that SCE&G and GENCO have already completed should assist Consolidated SCE&G in complying with CSAPR and 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, CSAPR, or other rules issued by the EPA in the future 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 things.

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 these sites will continue until 2015 and will cost an additional $7.9 million, which is accrued in Other within Deferred Credits and Other Liabilities on the consolidated balance sheet.  SCE&G expects to recover any cost arising from the remediation of MGP sites through rates and insurance settlements.  At June 30, 2012, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $24.3 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 to be 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, has 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 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 the 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) in 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 modules for the New Units and unanticipated rock conditions at the site.  A public hearing on this petition is set to begin on September 11, 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.

XML

CONSOLIDATED STATEMENTS OF INCOME (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Operating Revenues:
Electric Domestic Regulated Revenue	$ 592	$ 616	$ 1,137	$ 1,174
Gas-regulated	127	135	404	497
Gas-nonregulated	189	249	474	610
Regulated and Unregulated Operating Revenue	908	1,000	2,015	2,281
Operating Expenses [Abstract]
Fuel used in electric generation	198	251	379	462
Purchased power	4	8	10	10
Gas purchased for resale	223	297	588	810
Other operation and maintenance	170	165	345	334
Depreciation and amortization	89	86	178	172
Other taxes	53	51	106	103
Total Operating Expenses	737	858	1,606	1,891
Operating Income	171	142	409	390
Other Income (Expense):
Other income	12	11	26	24
Other expenses	(9)	(9)	(19)	(19)
Interest charges, net of allowance for borrowed funds used during construction	(73)	(70)	(145)	(139)
Allowance for equity funds used during construction	4	5	7	8
Total Other Expense	(66)	(63)	(131)	(126)
Income Before Income Tax Expense	105	79	278	264
Income Tax Expense	33	23	85	80
Income Available to Common Shareholders	72	56	193	184
Per Common Share Data
Basic Earnings Per Share of Common Stock (in dollars per share)	$ 0.55	$ 0.44	$ 1.48	$ 1.44
Diluted Earnings Per Share of Common Stock (in dollars per share)	$ 0.54	$ 0.43	$ 1.46	$ 1.42
Weighted Average Common Shares Outstanding (millions)
Weighted Average Number of Shares Outstanding, Basic	130.9	128.5	130.6	128.2
Weighted Average Number of Shares Outstanding, Diluted	133.1	129.7	132.7	129.4
Dividends Declared Per Share of Common Stock (in dollars per share)	$ 0.495	$ 0.485	$ 0.990	$ 0.970
SCE&G
Operating Revenues:
Electric Domestic Regulated Revenue	594	618	1,141	1,178
Gas-regulated	67	73	183	218
Total Operating Revenues	661	691	1,324	1,396
Operating Expenses [Abstract]
Fuel used in electric generation	199	252	382	465
Purchased power	4	8	10	10
Gas purchased for resale	37	49	96	136
Other operation and maintenance	134	127	272	260
Depreciation and amortization	74	71	147	142
Other taxes	48	47	96	94
Total Operating Expenses	496	554	1,003	1,107
Operating Income	165	137	321	289
Other Income (Expense):
Other income	0	1	0	2
Other expenses	(3)	(3)	(7)	(7)
Interest charges, net of allowance for borrowed funds used during construction	(52)	(50)	(103)	(100)
Allowance for equity funds used during construction	4	5	7	8
Total Other Expense	(51)	(47)	(103)	(97)
Income Before Income Tax Expense	114	90	218	192
Income Tax Expense	36	29	69	60
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	78	61	149	132
Net Income (Loss) Attributable to Noncontrolling Interest	2	2	6	5
Net Income (Loss) Attributable to Parent	76	59	143	127
Weighted Average Common Shares Outstanding (millions)
Dividends, Common Stock, Cash	54	49	107	100
Retail Gas Marketing
Operating Revenues:
Regulated and Unregulated Operating Revenue	71	78	224	280
Other Income (Expense):
Income Available to Common Shareholders	(3)	(3)	8	19
Adjustments/Eliminations
Operating Revenues:
Regulated and Unregulated Operating Revenue	(9)	(8)	(17)	(15)
Operating Expenses [Abstract]
Operating Income	(2)	(3)	19	34
Other Income (Expense):
Income Available to Common Shareholders	77	58	180	162
Adjustments/Eliminations | SCE&G
Operating Expenses [Abstract]
Operating Income	0	(1)		(1)
Other Income (Expense):
Net Income (Loss) Attributable to Parent	76	59	143	127
Electric Operations
Operating Revenues:
Regulated and Unregulated Operating Revenue	592	616	1,137	1,174
Operating Expenses [Abstract]
Operating Income	164	140	291	262
Electric Operations | SCE&G
Operating Revenues:
Total Operating Revenues	594	618	1,141	1,178
Operating Expenses [Abstract]
Operating Income	163	140	290	262
Energy Marketing
Operating Revenues:
Regulated and Unregulated Operating Revenue	118	172	250	330
Other Income (Expense):
Income Available to Common Shareholders	$ 2	$ 1	$ 4	$ 2

XML

COMMON EQUITY

6 Months Ended

Jun. 30, 2012

Stockholders' Equity Note [Abstract]

COMMON EQUITY

COMMON EQUITY

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

Millions of dollars	2012			2011
Balance at January 1,	$	3,889		$	3,702
Common stock issued	50			50
Dividends declared	(130		)	(124		)
Comprehensive income	201			177
Balance as of June 30,	$	4,010		$	3,805

Authorized shares of common stock were 200 million as of June 30, 2012 and December 31, 2011.  Outstanding shares of common stock were 131.0 million and 129.9 million at June 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 amendment dated October 26, 2011, are to be settled by December 31, 2012, though settlement may be effected later upon mutual agreement of all parties to the contracts.  SCANA expects to amend the forward sales contracts further and to settle them 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 six months ended June 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	51			—			51
Dividends declared	(103		)	(4		)	(107		)
Comprehensive income	143			6			149
Balance as of June 30, 2012	$	3,756		$	110		$	3,866
Balance at January 1, 2011	$	3,437		$	104		$	3,541
Capital contribution from parent	49			—			49
Dividends declared	(97		)	(3		)	(100		)
Comprehensive income	127			5			132
Balance as of June 30, 2011	$	3,516		$	106		$	3,622

Authorized shares of SCE&G common stock were 50 million as of June 30, 2012 and December 31, 2011.  Outstanding shares of common stock were 40.3 million at both June 30, 2012 and December 31, 2011. Authorized shares of SCE&G preferred stock were 20 million as of June 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.

XML

RATE AND OTHER REGULATORY MATTERS

6 Months Ended

Jun. 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.

On June 29, 2012, SCE&G filed an application with the SCPSC requesting an increase in 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 set to begin on November 27, 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 things. These units have an aggregate generating capacity (summer 2012) of 730 MW. The net carrying value of these units totaled $447 million at June 30, 2012, and is identified as Plant to be Retired, Net in the 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 things, 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.

In 2010, the SCPSC approved the 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 things, 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 the 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) in 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 to the consolidated financial statements).  A public hearing on this petition is set to begin on September 11, 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)
2011	2.4%	$52.8
2010	2.3%	$47.3

On May 30, 2012, SCE&G filed its annual request for approval of revised rates under the provisions of the BLRA. The annual request was for an overall increase of $56.7 million, or 2.5%, to its approved retail electric rates. If approved, the rate change would be effective for bills rendered on and after October 30, 2012.

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)
2011	2.1	%	Increase	$8.6
2010	2.1	%	Decrease	$10.4

On June 15, 2012, SCE&G filed with the SCPSC its quarterly monitoring report and proposed an $8.8 million, or 2.4%, overall increase to its natural gas rates under the terms of the natural gas RSA. The ORS is expected to issue an audit report by September 1, 2012, and the SCPSC is expected to issue an order by October 15, 2012. If approved, the rate adjustment would be effective with the first billing cycle in November.

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 conducted 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 to begin on 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 tenths 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 tenths 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 December 2011, in connection with PSNC Energy's 2011 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, 2011.

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	June 30, 2012		December 31, 2011
Regulatory Assets:
Accumulated deferred income taxes	$	243	$	243
Under-collections - electric fuel adjustment clause	—		28
Environmental remediation costs	30		30
AROs and related funding	320		316
Franchise agreements	38		40
Deferred employee benefit plan costs	387		392
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	163		154
Deferred pollution control costs	32		25
Other	52		45
Total Regulatory Assets	$	1,265	$	1,279

Regulatory Liabilities:
Accumulated deferred income taxes	$	21	$	23
Asset removal costs	680		662
Storm damage reserve	31		32
Monetization of bankruptcy claim	33		34
Deferred gains on interest rate derivatives	65		24
Planned major maintenance	5		—
Other	—		3
Total Regulatory Liabilities	$	835	$	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 17 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, although recovery periods could become longer at the direction of the SCPSC.

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 $9.2 million at June 30, 2012 and are being recovered through utility rates over approximately 30 years.  The remaining costs relate to Wateree Station, for which the Company is seeking recovery in a current proceeding before the SCPSC.  SCE&G is allowed to accrue interest on deferred costs related to Wateree Station.

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 six months ended June 30, 2012 and 2011, SCE&G applied costs of $1.5 million and $1.8 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. SCE&G is seeking to reinstate collection of storm damage reserve amounts in a current proceeding before the SCPSC.

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 these 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.

On June 29, 2012, SCE&G filed an application with the SCPSC requesting an increase in 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 set to begin on November 27, 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 things. These units have an aggregate generating capacity (summer 2012) of 730 MW. The net carrying value of these units totaled $447 million at June 30, 2012, and is identified as Plant to be Retired, Net in the 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 retirements, 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 things, 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.

In 2010, the SCPSC approved the 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 things, 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 the 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) in 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 to the consolidated financial statements).  A public hearing on this petition is set to begin on September 11, 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)
2011	2.4%	$52.8
2010	2.3%	$47.3

On May 30, 2012, SCE&G filed its annual request for approval of revised rates under the provisions of the BLRA. The annual request was for an overall increase of $56.7 million, or 2.5%, to its approved retail electric rates. If approved, the rate change would be effective for bills rendered on and after October 30, 2012.

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)
2011	2.1	%	Increase	$8.6
2010	2.1	%	Decrease	$10.4

On June 15, 2012, SCE&G filed with the SCPSC its quarterly monitoring report and proposed an $8.8 million, or 2.4%, overall increase to its natural gas rates under the terms of the natural gas RSA. The ORS is expected to issue an audit report by September 1, 2012, and the SCPSC is expected to issue an order by October 15, 2012. If approved, the rate adjustment would be effective with the first billing cycle in November.

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 conducted 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 to begin on 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	June 30, 2012		December 31, 2011
Regulatory Assets:
Accumulated deferred income taxes	$	238	$	238
Under collections – electric fuel adjustment clause	—		28
Environmental remediation costs	25		25
AROs and related funding	304		301
Franchise agreements	38		40
Deferred employee benefit plan costs	344		348
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	163		154
Deferred pollution control costs	32		25
Other	48		41
Total Regulatory Assets	$	1,192	$	1,206

Regulatory Liabilities:
Accumulated deferred income taxes	$	21	$	23
Asset removal costs	503		493
Storm damage reserve	31		32
Deferred gains on interest rate derivatives	65		24
Planned major maintenance	5		—
Other	—		3
Total Regulatory Liabilities	$	625	$	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 17 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, although recovery periods could become longer at the direction of the SCPSC.

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 $9.2 million at June 30, 2012 and are being recovered through utility rates over approximately 30 years.  The remaining costs relate to Wateree Station, for which SCE&G is seeking recovery in a current proceeding before the SCPSC.  SCE&G is allowed to accrue interest on deferred costs related to Wateree Station.

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 six months ended June 30, 2012 and 2011, SCE&G applied costs of $1.5 million and $1.8 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. SCE&G is seeking to reinstate collection of storm damage reserve amounts in a current proceeding before the SCPSC.

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 these 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)

6 Months Ended

Jun. 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	130.9	128.5	130.6	128.2
Net effect of dilutive equity forward shares	2.2	1.2	2.1	1.2
Weighted Average Shares - Diluted	133.1	129.7	132.7	129.4

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SEGMENT OF BUSINESS INFORMATION

6 Months Ended

Jun. 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 June 30, 2012
Electric Operations	$	592		$	3		$	164		n/a
Gas Distribution	126			—			5			n/a
Retail Gas Marketing	71			—			—			$	(3	)
Energy Marketing	118			23			—			2
All Other	10			103			4			(4		)
Adjustments/Eliminations	(9		)	(129		)	(2		)	77
Consolidated Total	$	908		—			$	171		$	72
Six Months Ended June 30, 2012
Electric Operations	$	1,137		$	5		$	291		n/a
Gas Distribution	400			—			88			n/a
Retail Gas Marketing	224			—			n/a			$	8
Energy Marketing	250			49			n/a			4
All Other	21			209			11			1
Adjustments/Eliminations	(17		)	(263		)	19			180
Consolidated Total	$	2,015		—			$	409		$	193
Three Months Ended June 30, 2011
Electric Operations	$	616		$	2		$	140		n/a
Gas Distribution	132			—			2			n/a
Retail Gas Marketing	78			—			n/a			$	(3	)
Energy Marketing	172			52			n/a			1
All Other	10			104			3			—
Adjustments/Eliminations	(8		)	(158		)	(3		)	58
Consolidated Total	$	1,000		—			$	142		$	56

Six Months Ended June 30, 2011
Electric Operations	$	1,174		$	4		$	262	n/a
Gas Distribution	492			—			86		n/a
Retail Gas Marketing	280			—			n/a		$	19
Energy Marketing	330			97			n/a		2
All Other	20			206			8		1
Adjustments/Eliminations	(15		)	(307		)	34		162
Consolidated Total	$	2,281		—			$	390	$	184

	June 30,		December 31,
Segment Assets	2012		2011
Electric Operations	$	8,589	$	8,222
Gas Distribution	2,201		2,179
Retail Gas Marketing	141		185
Energy Marketing	93		114
All Other	1,250		1,377
Adjustments/Eliminations	1,475		1,457
Consolidated Total	$	13,749	$	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 June 30, 2012
Electric Operations	$	594	$	163	n/a
Gas Distribution	67		2		n/a
Adjustments/Eliminations	—		—		$	76
Consolidated Total	$	661	$	165	$	76
Six Months Ended June 30, 2012
Electric Operations	$	1,141	$	290	n/a
Gas Distribution	183		31		n/a
Adjustments/Eliminations	—		—		$	143
Consolidated Total	$	1,324	$	321	$	143

Three Months Ended June 30, 2011
Electric Operations	$	618	$	140		n/a
Gas Distribution	73		(2		)	n/a
Adjustments/Eliminations	—		(1		)	$	59
Consolidated Total	$	691	$	137		$	59
Six Months Ended June 30, 2011
Electric Operations	$	1,178	$	262		n/a
Gas Distribution	218		28			n/a
Adjustments/Eliminations	—		(1		)	$	127
Consolidated Total	$	1,396	$	289		$	127

	June 30,		December 31,
Segment Assets	2012		2011
Electric Operations	$	8,589	$	8,222
Gas Distribution	636		622
Adjustments/Eliminations	2,206		2,193
Consolidated Total	$	11,431	$	11,037

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DERIVATIVE FINANCIAL INSTRUMENTS

6 Months Ended

Jun. 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 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.

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 other comprehensive income.  When the hedged transactions affect earnings, the previously recorded gains and losses are reclassified from other comprehensive income 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 supply futures and swaps are designated as hedges for accounting purposes.

Interest Rate Swaps

The Company uses 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 are designated as either fair value hedges or cash flow hedges.

The Company uses swaps to synthetically convert fixed rate debt to variable rate debt.  These swaps are designated as fair value hedges.  Periodic payments to or receipts from swap counterparties are recorded within interest expense and are classified as an operating activity in the consolidated statements of cash flows.  In addition, gains on certain swaps that were terminated prior to maturity of the underlying debt instruments are being amortized to interest expense over the life of the debt they hedged.

The Company synthetically converts variable rate debt to fixed rate debt using swaps that are designated as cash flow hedges.  Periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense and are classified as an operating activity for cash flow purposes.

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 other comprehensive income.  Such amounts are amortized to

interest expense over the term of the underlying debt. Ineffective portions are recognized in income.  Cash payments made or received upon termination of these financial instruments are classified as an investing activity in the consolidated statements of cash flows.

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 June 30, 2012
Cash flow	—	6,573,000	24,849,638	31,422,638
Not designated (a)	9,520,000	—	26,574,637	36,094,637
Total (a)	9,520,000	6,573,000	51,424,275	67,517,275
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 6,952,000 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 June 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 $1.0 billion at June 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 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 June 30, 2012
Derivatives designated as hedging instruments
Interest rate contracts	Prepayments and other	$	20	Other current liabilities	$	79
	Other deferred debits and other assets	8		Other deferred credits and other liabilities	41
Commodity contracts	Prepayments and other	2
	Other current liabilities	2		Other current liabilities	4
				Other deferred credits and other liabilities	2
Total		$	32		$	126
Derivatives not designated as hedging instruments
Energy management contracts	Prepayments and other	$	11	Prepayments and other	$	2
	Other deferred debits and other assets	10		Other current liabilities	10
				Other deferred credits and other liabilities	9
Total		$	21		$	21

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 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 as discussed above, resulted in increases to interest expense that were insignificant for each of the three and six months ended June 30, 2012 and were $1.5 million and $4.0 million for the three and six months ended June 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 June 30,
Interest rate contracts	$	(2	)	$	(15	)	Interest expense	$	—		$	—
Six Months Ended June 30,
Interest rate contracts	$	28		$	(9	)	Interest expense	$	(1	)	$	(1	)

	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 June 30,
Interest rate contracts	$	(4	)	$	(14	)	Interest expense	$	(1	)	$	(1	)
Commodity contracts	1			(1		)	Gas purchased for resale	(3		)	—
Total	$	(3	)	$	(15	)		$	(4	)	$	(1	)
Six Months Ended June 30,
Interest rate contracts	$	(4	)	$	(11	)	Interest expense	$	(3	)	$	(2	)
Commodity contracts	(3		)	(2		)	Gas purchased for resale	(11		)	(4		)
Total	$	(7	)	$	(13	)		$	(14	)	$	(6	)

As of June 30, 2012, the Company expects that during the next 12 months reclassifications from accumulated other comprehensive loss to earnings arising from cash flow hedges will include approximately $2.0 million as an increase to gas cost and approximately $6.7 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels.  As of June 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
Second Quarter
Commodity contracts	Gas purchased for resale	$	—		$	—
Year to Date
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 six months ended June 30, 2012 and 2011.

Credit Risk Considerations

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 June 30, 2012 and December 31, 2011, the Company has posted $116.1 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 June 30, 2012 and December 31, 2011, the Company would be required to post an additional $18.0 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 June 30, 2012 and December 31, 2011 is $134.1 million and $191.0 million, respectively.

SCE&G

Derivative [Line Items]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

DERIVATIVE FINANCIAL INSTRUMENTS

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

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 in the consolidated statements of cash flows.

Quantitative Disclosures Related to Derivatives

SCE&G was party to natural gas derivative contracts for 510,000 DT at June 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 $921.4 million at June 30, 2012 and $471.4 million at December 31, 2011.

The fair value of interest rate derivatives was reflected in the 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 June 30, 2012
Derivatives designated as hedging instruments
Interest rate contracts	Prepayments and other	$	20	Other current liabilities	$	75
	Other deferred debits and other assets	8		Other deferred credits and other liabilities	12
Total		$	28		$	87
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 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 June 30,
Interest rate contracts	$	(2	)	$	(15	)	Interest expense	$	—		$	—
Six Months Ended June 30,
Interest rate contracts	$	28		$	(9	)	Interest expense	$	(1	)	$	(1	)

Derivatives not designated as Hedging Instruments	Gain (Loss) Recognized in Income
Millions of dollars	Location	2012		2011
Second Quarter
Commodity contracts	Gas purchased for resale	—		—
Year to Date
Commodity contracts	Gas purchased for resale	(1	)	(1	)

Hedge Ineffectiveness

Other gains (losses) recognized in income representing interest rate hedge ineffectiveness were insignificant in each of the three and six months ended June 30, 2012 and 2011.

Credit Risk Considerations

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 June 30, 2012 and December 31, 2011, Consolidated SCE&G has posted $64.6 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 June 30, 2012 and December 31, 2011, Consolidated SCE&G would be required to post an additional $12.2 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 June 30, 2012 and December 31, 2011 is $76.8 million and $76.7 million, respectively.

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LONG-TERM AND SHORT-TERM DEBT

6 Months Ended

Jun. 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 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 of 6.25% 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	June 30, 2012			December 31, 2011			June 30, 2012			December 31, 2011			June 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)	$	84		$	131		$	586		$	512		—			$	10
Weighted average interest rate	0.88		%	0.63		%	0.49		%	0.56		%	—		%	0.57		%
Letters of credit supported by LOC	$	3		$	3		$	0.3		$	0.3		—			—
Available	$	213		$	166		$	514		$	588		$	100		$	90

SCANA, SCE&G (including Fuel Company) and PSNC Energy are parties to credit agreements in the amounts of $300 million, $1.1 billion, of which $400 million relates to Fuel Company, and $100 million, respectively, which expire October 23, 2015.  These credit agreements are used for general corporate purposes, including liquidity support for each company’s commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, fossil fuel, and emission and other environmental allowances.  These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provide 10.0% 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 provide 8.0%, and Deutsche Bank AG New York Branch, Union Bank, N.A. and U.S. Bank National Association each provide 5.3%.  Three other banks provide the remaining 6.0%. These bank credit facilities support the issuance of commercial paper by SCANA, SCE&G (including Fuel Company) and PSNC Energy. When the commercial paper markets are dislocated (due to either price or availability constraints), the credit facilities are available to support the borrowing needs of SCANA, SCE&G (including Fuel Company) and PSNC Energy.

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

6 Months Ended

Jun. 30, 2012

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, 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 June 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 June 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.

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FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

6 Months Ended

Jun. 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 June 30, 2012
Assets -	Available for sale securities	$	8	—
	Interest rate contracts	—		$	28
	Commodity contracts	1		2
	Energy management contracts	—		21
Liabilities -	Interest rate contracts	—		120
	Commodity contracts	1		6
	Energy management contracts	1		22
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 June 30, 2012 and December 31, 2011 were as follows:

	June 30, 2012				December 31, 2011
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	4,883.6	$	5,835.0	$	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.

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		June 30, 2012	December 31, 2011
Assets -	Interest rate contracts	$28	$1
Liabilities-	Interest rate contracts	87	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 June 30, 2012 and December 31, 2011 were as follows:

	June 30, 2012				December 31, 2011
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	3,482.4	$	4,282.1	$	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.”  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.

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RATE AND OTHER REGULATORY MATTERS (Details 3) (USD $)	3 Months Ended	24 Months Ended															3 Months Ended	6 Months Ended
	Jun. 30, 2012	Jul. 31, 2012	Dec. 31, 2011	Jun. 30, 2011	Jun. 30, 2012 Accumulated deferred income taxes	Dec. 31, 2011 Accumulated deferred income taxes	Jun. 30, 2012 Asset Retirement Obligation Costs [Member]	Dec. 31, 2011 Asset Retirement Obligation Costs [Member]	Jun. 30, 2012 Storm damage reserve	Dec. 31, 2011 Storm damage reserve	Jun. 30, 2012 Monetization of bankruptcy claim	Dec. 31, 2011 Monetization of bankruptcy claim	Jun. 30, 2012 Deferred gains on interest rate derivatives	Dec. 31, 2011 Deferred gains on interest rate derivatives	Jun. 30, 2012 Other.	Dec. 31, 2011 Other.	Jun. 30, 2012 SCE&G	Jun. 30, 2012 SCE&G	Jun. 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																	9,200,000	9,200,000
Regulatory liabilities	835,000,000		778,000,000	778,000,000	21,000,000	23,000,000	680,000,000	662,000,000	31,000,000	32,000,000	33,000,000	34,000,000	65,000,000	24,000,000	0	3,000,000	625,000,000	625,000,000		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																		$ 1,500,000	$ 1,800,000
Accrual period of nuclear refueling charges (in months)	18																18

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

6 Months Ended

Jun. 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 41%  and 45% of PSNC Energy’s natural gas inventory at June 30, 2012 and December 31, 2011, respectively, with a carrying value of $14.6 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 $485 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)

3 Months Ended

6 Months Ended

Jun. 30, 2012

Jun. 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	June 30, 2012			December 31, 2011			June 30, 2012			December 31, 2011			June 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)	$	84		$	131		$	586		$	512		—			$	10
Weighted average interest rate	0.88		%	0.63		%	0.49		%	0.56		%	—		%	0.57		%
Letters of credit supported by LOC	$	3		$	3		$	0.3		$	0.3		—			—
Available	$	213		$	166		$	514		$	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 our 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	June 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)	$	586		$	512
Weighted average interest rate	0.49		%	0.56		%
Letters of credit supported by LOC	$	0.3		$	0.3
Available	$	514		$	588

SCE&G and Fuel Company are parties to credit agreements in the amount of $1.1 billion, of which $400 million relates to Fuel Company, which expire October 23, 2015.  These credit agreements are used for general corporate purposes, including liquidity support for each company’s commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, fossil fuel, and emission and other environmental allowances.  These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provide 10.0% 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 provide 8.0%, and Deutsche Bank AG New York Branch, Union Bank, N.A. and U.S. Bank National Association each provide 5.3%.  Three other banks provide the remaining 6.0%. These bank credit facilities support the issuance of commercial paper by SCE&G (including Fuel Company).  When the commercial paper markets are dislocated (due to either price or availability constraints), the credit facilities are available to support the borrowing needs of SCE&G (including Fuel Company).

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

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	June 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)	$	586		$	512
Weighted average interest rate	0.49		%	0.56		%
Letters of credit supported by LOC	$	0.3		$	0.3
Available	$	514		$	588

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DERIVATIVE FINANCIAL INSTRUMENTS (Details 3) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 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		$ 1,500,000		$ 4,000,000
Effect of Cash Flow Hedges on Statement of Income
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	(4,000,000)	(1,000,000)	(14,000,000)	(6,000,000)
Gain or (Loss) Deferred in Regulatory Accounts (Effective Portion), classified in interest expense	(3,000,000)	15,000,000	(7,000,000)	(13,000,000)
Derivative, Credit Risk Related Contingent Features [Abstract]
Collateral Already Posted, Aggregate Fair Value	116,100,000		116,100,000		140,300,000
Additional collateral required to be posted to counterparties if all underlying contingent features were fully triggered	18,000,000		18,000,000		50,700,000
Aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position	134,100,000		134,100,000		0
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	3,000,000	0	11,000,000	4,000,000
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred	2,000,000
Gain or (Loss) Deferred in Regulatory Accounts (Effective Portion), classified in interest expense	(1,000,000)	1,000,000	3,000,000	2,000,000
Derivatives not designated as hedging instruments - gain (loss) recognized in income, classified in gas purchased for resale	0	0	(1,000,000)	(1)
Interest Rate Contract
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	(2,000,000)	(15,000,000)	28,000,000	(9,000,000)
Effect of Cash Flow Hedges on Statement of Income
Gain or (Loss) Deferred in Regulatory Accounts (Effective Portion), classified in interest expense	0	0	(1,000,000)	(1,000,000)
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	1,000,000	1,000,000	3,000,000	2,000,000
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred	6,700,000
Gain or (Loss) Deferred in Regulatory Accounts (Effective Portion), classified in interest expense	4,000,000	14,000,000	4,000,000	11,000,000
SCE&G
Derivative, Credit Risk Related Contingent Features [Abstract]
Collateral Already Posted, Aggregate Fair Value	0		0		0
Additional collateral required to be posted to counterparties if all underlying contingent features were fully triggered	0		0		0
Aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position	76.8		76.8		0
SCE&G | Interest Rate Contract
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	(2,000,000)	(15,000,000)	28,000,000	(9,000,000)
Effect of Cash Flow Hedges on Statement of Income
Gain or (Loss) Deferred in Regulatory Accounts (Effective Portion), classified in interest expense	$ 0	$ 0	$ (1,000,000)	$ (1,000,000)

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CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Interest charges, allowance for borrowed funds used during construction	$ 3	$ 3	$ 4	$ 5
SCE&G
Interest charges, allowance for borrowed funds used during construction	$ 3	$ 3	$ 4	$ 4

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

6 Months Ended

Jun. 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	130.9	128.5	130.6	128.2
Net effect of dilutive equity forward shares	2.2	1.2	2.1	1.2
Weighted Average Shares - Diluted	133.1	129.7	132.7	129.4

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 41%  and 45% of PSNC Energy’s natural gas inventory at June 30, 2012 and December 31, 2011, respectively, with a carrying value of $14.6 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 $485 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.

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DERIVATIVE FINANCIAL INSTRUMENTS (Tables)

6 Months Ended

Jun. 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 June 30, 2012
Cash flow	—	6,573,000	24,849,638	31,422,638
Not designated (a)	9,520,000	—	26,574,637	36,094,637
Total (a)	9,520,000	6,573,000	51,424,275	67,517,275
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 6,952,000 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 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 June 30, 2012
Derivatives designated as hedging instruments
Interest rate contracts	Prepayments and other	$	20	Other current liabilities	$	79
	Other deferred debits and other assets	8		Other deferred credits and other liabilities	41
Commodity contracts	Prepayments and other	2
	Other current liabilities	2		Other current liabilities	4
				Other deferred credits and other liabilities	2
Total		$	32		$	126
Derivatives not designated as hedging instruments
Energy management contracts	Prepayments and other	$	11	Prepayments and other	$	2
	Other deferred debits and other assets	10		Other current liabilities	10
				Other deferred credits and other liabilities	9
Total		$	21		$	21

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 June 30,
Interest rate contracts	$	(2	)	$	(15	)	Interest expense	$	—		$	—
Six Months Ended June 30,
Interest rate contracts	$	28		$	(9	)	Interest expense	$	(1	)	$	(1	)

	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 June 30,
Interest rate contracts	$	(4	)	$	(14	)	Interest expense	$	(1	)	$	(1	)
Commodity contracts	1			(1		)	Gas purchased for resale	(3		)	—
Total	$	(3	)	$	(15	)		$	(4	)	$	(1	)
Six Months Ended June 30,
Interest rate contracts	$	(4	)	$	(11	)	Interest expense	$	(3	)	$	(2	)
Commodity contracts	(3		)	(2		)	Gas purchased for resale	(11		)	(4		)
Total	$	(7	)	$	(13	)		$	(14	)	$	(6	)

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
Second Quarter
Commodity contracts	Gas purchased for resale	$	—		$	—
Year to Date
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 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 June 30, 2012
Derivatives designated as hedging instruments
Interest rate contracts	Prepayments and other	$	20	Other current liabilities	$	75
	Other deferred debits and other assets	8		Other deferred credits and other liabilities	12
Total		$	28		$	87
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 June 30,
Interest rate contracts	$	(2	)	$	(15	)	Interest expense	$	—		$	—
Six Months Ended June 30,
Interest rate contracts	$	28		$	(9	)	Interest expense	$	(1	)	$	(1	)

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

Derivatives not designated as Hedging Instruments	Gain (Loss) Recognized in Income
Millions of dollars	Location	2012		2011
Second Quarter
Commodity contracts	Gas purchased for resale	—		—
Year to Date
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
	Jun. 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

6 Months Ended

Jun. 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 $18.5 million and $15.8 million for the six months ended June 30, 2012 and 2011, respectively.  SCE&G had approximately $2.6 million and $2.5 million payable to CGT for transportation services at June 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 $48.8 million and $96.7 million for the six months ended June 30, 2012 and 2011, respectively.  SCE&G’s payables to SEMI for such purposes were $10.0 million and $13.2 million as of June 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 $6.4 million at June 30, 2012 and $8.5 million at December 31, 2011.  SCE&G’s payables to these affiliates were $6.4 million at June 30, 2012 and $8.6 million at December 31, 2011.  SCE&G’s total purchases were $46.9 million and $53.3 million for the six months ended June 30, 2012 and 2011, respectively.  SCE&G’s total sales were $46.6 million and $53.1 million for the six months ended June 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 six months ended June 30, 2012 or 2011.  At June 30, 2012 and December 31, 2011, Consolidated SCE&G owed an affiliate $70.1 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 $28 million and $43 million to the affiliate at June 30, 2012 and December 31, 2011, respectively, for invoices paid by the affiliate on behalf of Consolidated SCE&G.