10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

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

For the quarterly period ended March 31, 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 April 30, 2012
SCANA Corporation	Without Par Value	130,792,209
South Carolina Electric & Gas Company	Without Par Value	40,296,147 (a)

(a) Held beneficially and of record by SCANA Corporation.

This combined Form 10-Q is separately filed by SCANA Corporation and South Carolina Electric & Gas Company.  Information contained herein relating to any individual company is filed by such company on its own behalf.  Each company makes no representation as to information relating to the other company.

South Carolina Electric & Gas Company meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and therefore is filing this Form with the reduced disclosure format allowed under General Instruction H(2).

TABLE OF CONTENTS

MARCH 31, 2012

			Page
Cautionary Statement Regarding Forward-Looking Information			3
Definitions			4
PART I. FINANCIAL INFORMATION
SCANA Corporation Financial Section			6
	Item 1.	Financial Statements	7
		Condensed Consolidated Balance Sheets	7
		Condensed Consolidated Statements of Income	9
		Condensed Consolidated Statements of Comprehensive Income	10
		Condensed Consolidated Statements of Cash Flows	11
		Notes to Condensed Consolidated Financial Statements	12
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32
	Item 4.	Controls and Procedures	33
South Carolina Electric & Gas Company Financial Section			34
	Item 1.	Financial Statements	35
		Condensed Consolidated Balance Sheets	35
		Condensed Consolidated Statements of Income	37
		Condensed Consolidated Statements of Comprehensive Income	38
		Condensed Consolidated Statements of Cash Flows	39
		Notes to Condensed Consolidated Financial Statements	40
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	48
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	51
	Item 4.	Controls and Procedures	52
PART II. OTHER INFORMATION			53
	Item 6.	Exhibits	53
Signatures			54
Exhibit Index			55

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 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
LOC	Lines of credit
MGP	Manufactured Gas Plant
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
SCANA	SCANA Corporation, the parent company
SCANA Energy	A division of SEMI which markets natural gas in Georgia

4

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	March 31, 2012			December 31, 2011
Assets
Utility Plant In Service	$	12,071		$	12,000
Accumulated Depreciation and Amortization	(3,898		)	(3,836		)
Construction Work in Progress	1,694			1,482
Nuclear Fuel, Net of Accumulated Amortization	158			171
Goodwill, net of writedown of $230	230			230
Utility Plant, Net	10,255			10,047
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation of $135 and $131	304			305
Assets held in trust, net-nuclear decommissioning	87			84
Other investments	94			87
Nonutility Property and Investments, Net	485			476
Current Assets:
Cash and cash equivalents	27			29
Receivables, net of allowance for uncollectible accounts of $6 and $6	715			756
Inventories (at average cost):
Fuel and gas supply	312			313
Materials and supplies	128			129
Emission allowances	2			2
Prepayments and other	153			236
Deferred income taxes	22			26
Total Current Assets	1,359			1,491
Deferred Debits and Other Assets:
Regulatory assets	1,237			1,279
Other	244			241
Total Deferred Debits and Other Assets	1,481			1,520
Total	$	13,580		$	13,534

7

Millions of dollars	March 31, 2012		December 31, 2011
Capitalization and Liabilities
Common Equity	$	3,977	$	3,889
Long-Term Debt, net	4,862		4,622
Total Capitalization	8,839		8,511
Current Liabilities:
Short-term borrowings	585		653
Current portion of long-term debt	30		31
Accounts payable	342		374
Customer deposits and customer prepayments	95		103
Taxes accrued	53		154
Interest accrued	73		74
Dividends declared	65		63
Derivative financial instruments	27		77
Other	75		113
Total Current Liabilities	1,345		1,642
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,583		1,533
Deferred investment tax credits	39		40
Asset retirement obligations	479		474
Postretirement benefits	293		291
Regulatory liabilities	797		778
Other	205		265
Total Deferred Credits and Other Liabilities	3,396		3,381
Commitments and Contingencies (Note 9)	—		—
Total	$	13,580	$	13,534

See Notes to Condensed Consolidated Financial Statements.

8

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended March 31,
Millions of dollars, except per share amounts	2012			2011
Operating Revenues:
Electric	$	545		$	558
Gas - regulated	277			362
Gas - nonregulated	285			361
Total Operating Revenues	1,107			1,281
Operating Expenses:
Fuel used in electric generation	181			211
Purchased power	6			2
Gas purchased for resale	366			512
Other operation and maintenance	175			170
Depreciation and amortization	89			86
Other taxes	52			52
Total Operating Expenses	869			1,033
Operating Income	238			248
Other Income (Expense):
Other income	14			13
Other expenses	(10		)	(9		)
Interest charges, net of allowance for borrowed funds used during construction of $2 and $2	(72		)	(70		)
Allowance for equity funds used during construction	3			3
Total Other Expense	(65		)	(63		)
Income Before Income Tax Expense	173			185
Income Tax Expense	52			57
Net Income	$	121		$	128
Per Common Share Data
Basic Earnings Per Share of Common Stock	$	.93		$	1.00
Diluted Earnings Per Share of Common Stock	$	.91		$	1.00
Weighted Average Common Shares Outstanding (millions)
Basic	130.3			127.9
Diluted	132.2			129.0
Dividends Declared Per Share of Common Stock	$	.495		$	.485

See Notes to Condensed Consolidated Financial Statements.

9

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited) 

	Three Months Ended March 31,
Millions of dollars	2012			2011
Net Income	$	121		$	128
Other Comprehensive Income (Loss), net of tax:
Unrealized gains (losses) on cash flow hedging activities arising during period, net of tax expense (benefit) of $(2) and $1	(4		)	2
Losses on cash flow hedging activities reclassified to net income, net of tax benefit of $6 and $3	10			5
Other Comprehensive Income	6			7
Total Comprehensive Income (1)	$	127		$	135

(1)  Accumulated other comprehensive loss totaled $88.1 million as of March 31, 2012 and $93.8 million as of December 31, 2011.

See Notes to Condensed Consolidated Financial Statements.

10

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited) 

	Three Months Ended March 31,
Millions of dollars	2012			2011
Cash Flows From Operating Activities:
Net income	$	121		$	128
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	50			11
Depreciation and amortization	92			88
Amortization of nuclear fuel	13			9
Allowance for equity funds used during construction	(3		)	(3		)
Cash provided (used) by changes in certain assets and liabilities:
Receivables	65			192
Inventories	(11		)	17
Prepayments and other	68			83
Regulatory liabilities	1			(2		)
Accounts payable	(18		)	(146		)
Taxes accrued	(101		)	(99		)
Interest accrued	(1		)	—
Regulatory assets	41			14
Changes in other assets	(43		)	—
Changes in other liabilities	(89		)	(52		)
Net Cash Provided From Operating Activities	185			241
Cash Flows From Investing Activities:
Property additions and construction expenditures	(321		)	(295		)
Proceeds from investments (including derivative collateral posted)	151			1
Purchase of investments (including derivative collateral posted)	(109		)	(6		)
Proceeds from interest rate contract settlement	13			—
Payments for interest rate contract settlement	(51		)	—
Net Cash Used For Investing Activities	(317		)	(300		)
Cash Flows From Financing Activities:
Proceeds from issuance of common stock	26			25
Proceeds from issuance of long-term debt	494			379
Repayment of long-term debt	(259		)	(309		)
Dividends	(63		)	(61		)
Short-term borrowings, net	(68		)	92
Net Cash Provided From Financing Activities	130			126
Net (Decrease) Increase In Cash and Cash Equivalents	(2		)	67
Cash and Cash Equivalents, January 1	29			55
Cash and Cash Equivalents, March 31	$	27		$	122
Supplemental Cash Flow Information:
Cash paid for– Interest (net of capitalized interest of $2 and $2)	$	74		$	67
– Income taxes	—			—
Noncash Investing and Financing Activities:
Accrued construction expenditures	108			93

 See Notes to Condensed Consolidated Financial Statements.

11

SCANA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

For the Three Months Ended March 31, 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:

In Millions	2012	2011
Weighted Average Shares Outstanding - Basic	130.3	127.9
Net effect of dilutive equity forward shares	1.9	1.1
Weighted Average Shares - Diluted	132.2	129.0

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 27%  and 45% of PSNC Energy’s natural gas inventory at March 31, 2012 and December 31,2011, respectively, with a carrying value of $10.9 million and $28.7 million, respectively, through either capacity release or agency relationships.  Under the terms of the asset management agreements, PSNC Energy receives storage asset management fees.  No fees are received under supply service agreements.  The agreements expire at various times through March 31, 2013.

New Accounting Matters

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

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

12

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

2. RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric

SCE&G's retail electric rates are established in part by using a cost of fuel component approved by the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased by SCE&G. In February 2012, SCE&G requested authorization to decrease the total fuel cost component of its retail electric rates to be effective the first billing cycle of May 2012. On March 15, 2012, SCE&G, 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. By order dated April 24, 2012, the SCPSC approved the settlement agreement.

On July 15, 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 its annual update on DSM Programs and rate rider. By order dated May 24, 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 its annual update on DSM Programs and rate rider. By order dated April 25, 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 becomes 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.

    On November 15, 2010, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost schedule that, among other things, incorporated then-identifiable capital costs of $173.9 million (SCE&G's portion in 2007 dollars), and by order dated May 16, 2011, the SCPSC approved the updated capital costs schedule as outlined in the petition.

 On February 29, 2012, SCE&G filed a petition with the SCPSC seeking an order approving a further updated capital cost and construction schedule that incorporates additional identifiable capital costs of approximately of $6 million (SCE&G's portion in 2007 dollars) related to new federal healthcare laws, information security measures, and certain minor design modifications. That petition also includes increased capital costs of approximately $12 million (SCE&G's portion in 2007 dollars) related to transmission infrastructure. Finally, that petition includes amounts of approximately $137 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. That petition is expected to be recalled and replaced with a new petition which will include the costs arising from the resolution of the commercial claims discussed in Note 9 to the consolidated financial statements (e.g., those 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).

13

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

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

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.

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 adjusted periodically 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-collections of the delivered cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy’s gas purchasing practices annually. In addition, PSNC Energy utilizes a CUT which allows it to adjust its base rates semi-annually for residential and commercial customers based on average per customer consumption.

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

In 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. On February 2, 2012, the Public Staff of the NCUC filed a motion requesting the NCUC reconsider and modify its order by reassigning certain charges (totaling approximately $0.4 million) from the cost of gas. On April 4, 2012 the NCUC issued an order denying the Public Staff's motion for reconsideration.

14

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	March 31, 2012		December 31, 2011
Regulatory Assets:
Accumulated deferred income taxes	$	243	$	243
Under-collections - electric fuel adjustment clause	6		28
Environmental remediation costs	30		30
AROs and related funding	319		316
Franchise agreements	39		40
Deferred employee benefit plan costs	390		392
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	134		154
Deferred pollution control costs	29		25
Other	47		45
Total Regulatory Assets	$	1,237	$	1,279

Regulatory Liabilities:
Accumulated deferred income taxes	$	22	$	23
Asset removal costs	671		662
Storm damage reserve	31		32
Monetization of bankruptcy claim	34		34
Deferred gains on interest rate derivatives	37		24
Other	2		3
Total Regulatory Liabilities	$	797	$	778

Accumulated deferred income tax liabilities arising 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 by April 2013.  SCE&G is allowed to accrue interest on the base fuel deferred balances through the recovery period.

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 23 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

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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 this purpose.  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 $9.3 million at March 31, 2012 and are being recovered through utility rates over approximately 30 years.  The remaining costs relate to Wateree Station, for which the Company will seek recovery in future proceedings 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 three months ended March 31, 2012 and 2011, SCE&G applied costs of $0.8 million and $0.7 million, respectively, to the reserve.  Pursuant to the SCPSC’s July 2010 retail electric rate order approving an electric rate increase, SCE&G suspended collection of storm damage reserve funds indefinitely.

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

The SCPSC, the NCUC or the FERC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other regulatory assets include, but are not limited to, certain costs which have not been approved for recovery by the SCPSC or by FERC. In recording 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 three months ended March 31, 2012 and 2011 were as follows:

Millions of dollars	2012			2011
Balance at January 1,	$	3,889		$	3,702
Common stock issued	26			25
Dividends declared	(65		)	(62		)
Comprehensive income	127			135
Balance as of March 31,	$	3,977		$	3,800

Authorized shares of common stock were 200 million as of March 31, 2012 and December 31, 2011.  Outstanding shares of common stock were 130.4 million and 127.4 million at March 31, 2012 and December 31, 2011, respectively.

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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 no later than December 31, 2012.  There have been no shares issued under the forward sales contracts.

4. LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

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.

In January 2012, SCE&G issued $250 million of 4.35% first mortgage bonds due February 1, 2042. Proceeds from the sale 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 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	March 31, 2012			December 31, 2011			March 31, 2012			December 31, 2011			March 31, 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)	$	117		$	131		$	468		$	512		—			$	10
Weighted average interest rate	0.85		%	0.63		%	0.50		%	0.56		%	—		%	0.57		%
Letters of credit supported by LOC	$	3		$	3		$	0.3		$	0.3		—			—
Available	$	180		$	166		$	632		$	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 the change in method of accounting for certain repair costs in prior years, the Company had previously recorded approximately $38 million of unrecognized tax benefit. During the first quarter of 2012, new

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administrative 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 March 31, 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.

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.

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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 March 31, 2012
Cash flow	—	4,141,000	27,592,275	31,733,275
Not designated (a)	10,100,000	—	30,427,609	40,527,609
Total (a)	10,100,000	4,141,000	58,019,884	72,260,884
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 8,694,000 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 party to interest rate swaps designated as fair value hedges with aggregate notional amounts of $3.2 million and $253.2 million at March 31, 2012 and December 31, 2011, respectively, and was party to interest rate swaps designated as cash flow hedges with aggregate notional amounts of $322.6 million and $822.6 million, respectively.

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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 March 31, 2012
Derivatives designated as hedging instruments
Interest rate contracts	Prepayments and other	—		Other current liabilities	$	5
				Other deferred credits and other liabilities	80
Commodity contracts	Prepayments and other	$	1	Prepayments and other	2
	Other current liabilities	1		Other current liabilities	7
				Other deferred credits and other liabilities	2
Total		$	2		$	96
Derivatives not designated as hedging instruments
Energy management contracts	Prepayments and other	$	19	Prepayments and other	$	3
	Other deferred debits and other assets	12		Other current liabilities	16
				Other deferred credits and other liabilities	11
Total		$	31		$	30

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 (reductions) to interest expenses of $0.2 million and $(2.5) million for the three months ended March 31, 2012 and 2011, respectively.

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Derivatives in Cash Flow Hedging Relationships

	Gain (Loss) Deferred		Gain (Loss) Reclassified from
Derivatives in Cash Flow	in Regulatory Accounts		Deferred Accounts into Income
Hedging Relationships	(Effective Portion)		(Effective Portion)
Millions of dollars			Location	Amount
Three Months Ended March 31, 2012
Interest rate contracts	$	30	Interest expense	$	(1	)
Three Months Ended March 31, 2011
Interest rate contracts	$	6	Interest expense	$	(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
Three Months Ended March 31, 2012
Interest rate contracts	$	—		Interest expense	$	(2	)
Commodity contracts	(4		)	Gas purchased for resale	(8		)
Total	$	(4	)		$	(10	)
Three Months Ended March 31, 2011
Interest rate contracts	$	3		Interest expense	$	(1	)
Commodity contracts	(1		)	Gas purchased for resale	(4		)
Total	$	2			$	(5	)

As of March 31, 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 $4.9 million as an increase to gas cost and approximately $5.8 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels.  As of March 31, 2012, all of the Company’s commodity cash flow hedges settle by their terms before the end of 2014.

Derivatives not designated as Hedging Instruments	Gain (Loss) Recognized in Income
Millions of dollars	Location	2012			2011
First Quarter
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 months ended March 31, 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 March 31, 2012 and December 31, 2011, the Company has posted $94.0 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 March 31, 2012 and December 31, 2011, the Company would be required to post an additional $25.5 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 March 31, 2012 and December 31, 2011 is $119.5 million and $191.0 million, respectively.

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7.

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

The Company values available for sale securities using quoted prices from a national stock exchange, such as the NASDAQ, where the securities are actively traded.  For commodity derivative 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)
Assets -	Available for sale securities	$	8	—
	Energy management contracts	—		$	31
	Commodity contracts	1		1
Liabilities -	Interest rate contracts	—		85
	Commodity contracts	2		9
	Energy management contracts	3		29
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 March 31, 2012 and December 31, 2011 were as follows:

	March 31, 2012				December 31, 2011
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	4,891.9	$	5,669.6	$	4,653.0	$	5,479.2

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

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8. EMPLOYEE BENEFIT PLANS

Pension and Other Postretirement Benefit Plans

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

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2012			2011			2012		2011
Three months ended March 31,
Service cost	$	4.8		$	4.6		$	1.3	$	1.1
Interest cost	10.7			11.1			3.0		3.0
Expected return on assets	(14.8		)	(16.2		)	—		—
Prior service cost amortization	1.7			1.8			0.2		0.3
Transition obligation amortization	—			—			0.2		0.2
Amortization of actuarial loss	4.7			3.0			0.2		0.1
Net periodic benefit cost	$	7.1		$	4.3		$	4.9	$	4.7

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 or income related to retail electric and gas operations as a regulatory asset or liability, as applicable.  Costs totaling $3.7 million and $2.3 million were deferred for the three months ended March 31, 2012 and 2011, respectively. 

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

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.

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 2014 and will cost an additional $8.1 million, which is accrued in Other within Deferred Credits and Other Liabilities on the consolidated balance sheet.  SCE&G expects to recover any cost arising from the remediation of MGP sites through rates and insurance settlements.  At March 31, 2012, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $24.5 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 March 31, 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 two1,117-MW nuclear generation units to be constructed at the site

24

of Summer Station, with SCE&G responsible for 55 percent of the cost and receiving 55 percent of the output, and Santee Cooper responsible for and receiving the remaining 45 percent.  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 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, including those 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.  These issues resulted in assertions of contractual entitlement to recover additional costs to be incurred. On March 29, 2012, SCE&G and the Consortium signed a preliminary agreement which set SCE&G's portion of these costs 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 included in future rate filings and will be recoverable through rates.

On February 29, 2012, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost and construction schedule that incorporates 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. That petition also includes increased capital costs of approximately $12 million (SCE&G's portion in 2007 dollars) related to transmission infrastructure. Finally, that petition includes amounts of approximately $137 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. It is anticipated that this petition will be recalled and replaced with a new petition which will also include the $138 million of additional costs referred to above.

Schedule changes identified in connection with COL delays, as well as the additional costs described above, are likely to result in changes to the amounts and timing of capital expenditures to be reflected in future quarterly reports to the SCPSC under the BLRA and in annual rate filings.  The results of an evaluation of the impact of certain of these changes are expected to be identified in the quarterly report to be filed on May 15, 2012.

When the NRC issued the COLs for the New Units, it imposed two conditions on the COLs, with the first requiring inspection and testing of certain components of the New Units' passive cooling system, and the second requiring the development of strategies to respond to extreme natural events resulting in the loss of power at the New Units.  In addition, the NRC directed the Office of New Reactors to issue to SCE&G an order requiring enhanced, reliable spent fuel pool instrumentation, as well as a request for information related to emergency plant staffing.  These conditions and requirements are responsive to the NRC's Near-Term Task Force report titled “Recommendations for Enhancing Reactor Safety in the 21st Century.”  This report was prepared in the wake of the March 2011 tsunami resulting from a massive earthquake, which severely damaged several nuclear generating units and their back-up cooling systems in Japan.  SCE&G is evaluating the impact these conditions and requirements impose on the construction and operation of the New Units.  SCE&G cannot predict what additional regulatory or other outcomes may be implemented in the United States, or how such initiatives would impact SCE&G's existing Summer Station or the construction or operation of the New Units.

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

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10. 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		Segment
Millions of dollars	Revenue			Revenue			Income		Income		Assets
Three Months Ended March 31, 2012
Electric Operations	$	545		$	2		$	127	n/a		$	8,449
Gas Distribution	274			—			83		n/a		2,277
Retail Gas Marketing	153			—			n/a		$	11	157
Energy Marketing	132			26			n/a		2		95
All Other	11			106			7		5		1,337
Adjustments/Eliminations	(8		)	(134		)	21		103		1,265
Consolidated Total	$	1,107		$	—		$	238	$	121	$	13,580
Three Months Ended March 31, 2011
Electric Operations	$	558		$	2		$	122	n/a		$	8,002
Gas Distribution	360			—			84		n/a		2,177
Retail Gas Marketing	202			—			n/a		$	22	201
Energy Marketing	158			45			n/a		1		95
All Other	10			102			5		1		1,262
Adjustments/Eliminations	(7		)	(149		)	37		104		1,136
Consolidated Total	$	1,281		$	—		$	248	$	128	$	12,873

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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 MONTHS ENDED MARCH 31, 2012

AS COMPARED TO THE CORRESPONDING PERIOD IN 2011

Earnings Per Share

Earnings per share was as follows:

Millions of dollars	2012	2011
Basic earnings per share	$0.93	$0.00
Diluted earnings per share	$0.91	$0.00

Basic earnings per share decreased by $.07 due to lower gas margin, $.03 due to higher operating expenses, $.02 due to higher depreciation expense, $.01 due to higher interest expense and by dilution from additional shares outstanding of $.02.  These decreases were partially offset by $.07 due to higher electric margin and $.01 due to other.

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.

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

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:

Millions of dollars	2012		% Change		2011
Operating revenues	$	547.4	(2.3	)%	$	560.3
Less:  Fuel used in generation	182.7		(14.1	)%	212.6
Purchased power	5.7		147.8	%	2.3
Margin	$	359.0	3.9	%	$	345.4

Margin increased primarily due to a $12.7 million increase in base rates approved by the SCPSC under the BLRA.

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

Classification	2012	% Change		2011
Residential	1,691	(17.8	)%	2,058
Commercial	1,644	(0.4	)%	1,650
Industrial	1,385	(2.2	)%	1,416
Other	135	6.3	%	127
Total Retail Sales	4,855	(7.5	)%	5,251
Wholesale	634	31.8	%	481
Total Sales	5,489	(4.2	)%	5,732

Retail sales volume decreased primarily due to the effects of milder weather. The increase in wholesale sales is due to higher contract utilization by a specific 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:

Millions of dollars	2012		% Change		2011
Operating revenues	$	274.6	(23.7	)%	$	359.8
Less:  Gas purchased for resale	128.6		(40.3	)%	215.5
Margin	$	146.0	1.2	%	$	144.3

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

Classification (in thousands)	2012	% Change		2011
Residential	15,026	(26.0	)%	20,309
Commercial	8,366	(19.2	)%	10,350
Industrial	5,446	2.3	%	5,326
Transportation	10,223	6.8	%	9,574
Total	39,061	(14.3	)%	45,559

Margin at PSNC Energy increased by $1.5 million primarily due to 1.6% residential and commercial customer growth.  Total sales volumes decreased primarily due to decreased firm customer usage resulting from milder weather.

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:

Millions	2012		% Change		2011
Operating revenues	$	152.8	(24.5	)%	$	202.4
Net Income	11.1		(48.6	)%	21.6

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

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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:

Millions	2012		% Change		2011
Operating revenues	$	158.2	(22.3	)%	$	203.6
Net Income	1.7		41.7	%	1.2

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

Other Operating Expenses

Other operating expenses were as follows:

Millions of dollars	2012		% Change		2011
Other operation and maintenance	$	175.2	3.2	%	$	169.7
Depreciation and amortization	88.7		3.4	%	85.8
Other taxes	52.6		1.5	%	51.8

Other operation and maintenance expenses increased by $3.9 million due to higher generation, transmission and distribution expenses, by $3.5 million due to higher compensation and other benefits and by $1.0 million due to higher 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 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) as noncash items, 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 months ended March 31, 2012 were lower than the same period in 2011 primarily due to lower income before taxes, which excludes the allowance for equity funds used during construction, a nontaxable item, partially offset by the higher recognition of certain previously deferred state income tax credits in 2011.

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 three and 12 months ended March 31, 2012 was 3.31 and 2.82, respectively.

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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	March 31, 2012			December 31, 2011			March 31, 2012			December 31, 2011			March 31, 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)	$	117		$	131		$	468		$	512		—			$	10
Weighted average interest rate	0.85		%	0.63		%	0.50		%	0.56		%	—		%	0.57		%
Letters of credit supported by LOC	$	3		$	3		$	0.3		$	0.3		—			—
Available	$	180		$	166		$	632		$	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.

At March 31, 2012, the Company had net available liquidity of approximately $938.6 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, while maintaining appropriate levels of liquidity.  The Company’s long-term debt portfolio has a weighted average maturity of approximately 18 years and bears an average 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 $26 million of stock during the three months ended March 31, 2012 through various compensation and dividend reinvestment plans.  Similar issuances are expected in future quarters. In addition, the Company expects to issue approximately 6.6 million common shares under forward sales contracts to be settled no later than December 31, 2012, which will result in net proceeds of approximately $196 million.

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.

In January 2012, SCE&G issued $250 million of 4.35% first mortgage bonds due February 1, 2042. Proceeds from the sale 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.

The Company paid approximately $38 million, net in 2012 to settle interest rate contracts associated with the issuance of long-term debt.

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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 percent of the cost and receiving 55 percent of the output, and Santee Cooper responsible for and receiving the remaining 45 percent.  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 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, including those 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.  These issues resulted in assertions of contractual entitlement to recover additional costs to be incurred. On March 29, 2012, SCE&G and the Consortium signed a preliminary agreement which set SCE&G's portion of these costs 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 included in future rate filings and will be recoverable through rates.

On February 29, 2012, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost and construction schedule that incorporates 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. That petition also includes increased capital costs of approximately $12 million (SCE&G's portion in 2007 dollars) related to transmission infrastructure. Finally, that petition includes amounts of approximately $137 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. It is anticipated that this petition will be recalled and replaced with a new petition which will include the $138 million of additional costs referred to above.

Schedule changes identified in connection with COL delays, as well as the additional costs described above, are likely to result in changes to the amounts and timing of capital expenditures to be reflected in future quarterly reports to the SCPSC under the BLRA and in annual rate filings.  The results of an evaluation of the impact of certain of these changes are expected to be identified in the quarterly report to be filed on May 15, 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.

31

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.  See Note 6 of the condensed consolidated financial statements.  The following tables provide information about the Company’s financial instruments that are sensitive to changes in natural gas prices.  Weighted average settlement prices are per 10,000 DT.  Fair value represents quoted market prices for these or similar instruments.

Expected Maturity:
Futures Contracts			Options
				Purchased Call	Purchased Put	Sold Call	Sold Put
2012	Long	Short	2012	(Long)	(Short)	(Short)	(Long)
Settlement Price (a)	2.51	3.95	Strike Price (a)	4.07	2.40	2.80	2.40
Contract Amount (b)	14.3	—	Contract Amount (b)	23.5	0.3	0.3	0.3
Fair Value (b)	10.7	0.1	Fair Value (b)	0.5	—	—	—
2013			2013
Settlement Price (a)	3.38	—	Strike Price (a)	3.92	—	—	—
Contract Amount (b)	7.7	—	Contract Amount (b)	17.5	—	—	—
Fair Value (b)	7.1	—	Fair Value (b)	1.1	—	—	—
2014
Settlement Price (a)	3.99
Contract Amount (b)	0.1
Fair Value (b)	0.1

(a)  Weighted average, in dollars

(b)  Millions of dollars

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Swaps	2012	2013	2014	2015	2016
Commodity Swaps:
Pay fixed/receive variable (b)	52.3	28.1	12.2	12.1	6.7
Average pay rate (a)	4.1893	5.0493	5.2963	5.3108	5.0491
Average received rate (a)	2.5556	3.4379	3.9556	4.2582	4.5128
Fair value (b)	31.9	19.2	9.1	9.7	6.0
Pay variable/receive fixed (b)	28.8	18.5	9.0	9.7	6.0
Average pay rate (a)	2.5438	3.4395	3.9559	4.2582	4.5128
Average received rate (a)	4.0134	4.7643	5.3188	5.3208	5.0559
Fair value (b)	45.5	25.6	12.1	12.1	6.7
Basis Swaps:
Pay variable/receive variable (b)	14.1	10.7	—	—	—
Average pay rate (a)	2.5253	3.4372	—	—	—
Average received rate (a)	2.5091	3.4208	—	—	—
Fair value (b)	14.0	10.6	—	—	—
(a) Weighted average, in dollars
(b) Millions of dollars

ITEM 4. CONTROLS AND PROCEDURES

As of March 31, 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 March 31, 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 March 31, 2012 that has materially affected or is reasonably likely to materially affect SCANA’s internal control over financial reporting.

33

SOUTH CAROLINA ELECTRIC & GAS COMPANY

FINANCIAL SECTION

34

Item 1. FINANCIAL STATEMENTS

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

Millions of dollars	March 31, 2012			December 31, 2011
Assets
Utility Plant In Service	$	10,376		$	10,312
Accumulated Depreciation and Amortization	(3,425		)	(3,367		)
Construction Work in Progress	1,679			1,472
Nuclear Fuel, Net of Accumulated Amortization	158			171
Utility Plant, Net ($647 and $662 related to VIEs)	8,788			8,588
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	53			52
Assets held in trust, net - nuclear decommissioning	87			84
Other investments	5			2
Nonutility Property and Investments, Net	145			138
Current Assets:
Cash and cash equivalents	24			16
Receivables, net of allowance for uncollectible accounts of $3 and $3	478			482
Affiliated receivables	9			9
Inventories (at average cost):
Fuel and gas supply	222			196
Materials and supplies	119			120
Emission allowances	2			2
Prepayments and other	79			82
Deferred income taxes	7			8
Total Current Assets ($227 and $193 related to VIEs)	940			915
Deferred Debits and Other Assets:
Regulatory assets	1,164			1,206
Other	180			190
Total Deferred Debits and Other Assets ($60 and $61 related to VIEs)	1,344			1,396
Total	$	11,217		$	11,037

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Millions of dollars	March 31, 2012		December 31, 2011
Capitalization and Liabilities
Common equity	$	3,707	$	3,665
Noncontrolling interest	109		108
Long-Term Debt, net	3,464		3,222
Total Capitalization	7,280		6,995
Current Liabilities:
Short-term borrowings	468		512
Current portion of long-term debt	19		19
Accounts Payable	252		231
Affiliated Payables	143		136
Customer deposits and customer prepayments	51		54
Taxes accrued	70		150
Interest accrued	51		54
Dividends declared	53		39
Derivative financial instruments	2		2
Other	37		61
Total Current Liabilities	1,146		1,258
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,414		1,371
Deferred investment tax credits	39		40
Asset retirement obligations	455		449
Postretirement benefits	181		179
Regulatory liabilities	590		575
Other	112		170
Total Deferred Credits and Other Liabilities	2,791		2,784
Commitments and Contingencies (Note 9)	—		—
Total	$	11,217	$	11,037

See Notes to Condensed Consolidated Financial Statements.

36

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited) 

	Three Months Ended March 31,
Millions of dollars	2012			2011
Operating Revenues:
Electric	$	547		$	560
Gas	116			144
Total Operating Revenues	663			704
Operating Expenses:
Fuel used in electric generation	183			213
Purchased power	6			2
Gas purchased for resale	59			88
Other operation and maintenance	138			132
Depreciation and amortization	73			71
Other taxes	48			47
Total Operating Expenses	507			553
Operating Income	156			151
Other Income (Expense):
Other income	—			1
Other expenses	(4		)	(4		)
Interest charges, net of allowance for borrowed funds used during construction of $2 and $2	(51		)	(50		)
Allowance for equity funds used during construction	3			3
Total Other Expense	(52		)	(50		)
Income Before Income Tax Expense	104			101
Income Tax Expense	32			31
Net Income	72			70
Less Net Income Attributable to Noncontrolling Interest	3			2
Earnings Available to Common Shareholder	$	69		$	68
Dividends Declared on Common Stock	$	53		$	51

See Notes to Condensed Consolidated Financial Statements.

37

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended March 31,
Millions of dollars	2012			2011
Net Income	$	72		$	70
Other Comprehensive Income, net of tax:
Amortization of deferred employee benefit plan costs reclassified to net income	—			—
Total Comprehensive Income	72			70
Less comprehensive income attributable to noncontrolling interest	(3		)	(2		)
Comprehensive income available to common shareholder (1)	$	69		$	68

(1)  Accumulated other comprehensive loss totaled $3.2 million as of March 31, 2012 and $3.3 million as of December 31, 2011.

See Notes to Condensed Consolidated Financial Statements.

38

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
Millions of dollars	2012			2011
Cash Flows From Operating Activities:
Net income	$	72		$	70
Adjustments to reconcile net income to net cash provided from operating activities:
Losses from equity method investments	1			—
Deferred income taxes, net	44			8
Depreciation and amortization	73			74
Amortization of nuclear fuel	13			9
Allowance for equity funds used during construction	(3		)	(3		)
Cash provided (used) by changes in certain assets and liabilities:
Receivables	28			107
Inventories	(38		)	(13		)
Prepayments and other	2			59
Regulatory assets	41			13
Regulatory liabilities	1			(1		)
Accounts payable	15			(67		)
Taxes accrued	(80		)	(96		)
Interest accrued	(3		)	(2		)
Changes in other assets	(1		)	(4		)
Changes in other liabilities	(78		)	(36		)
Net Cash Provided From Operating Activities	87			118
Cash Flows From Investing Activities:
Property additions and construction expenditures	(295		)	(269		)
Proceeds from investments (including derivative collateral posted)	52			1
Purchase of investments (including derivative collateral posted)	(50		)	(2		)
Proceeds from interest rate contract settlement	13			—
Net Cash Used For Investing Activities	(280		)	(270		)
Cash Flows From Financing Activities:
Proceeds from issuance of long-term debt	248			229
Repayment of long-term debt	(8		)	(157		)
Dividends	(39		)	(54		)
Contributions from parent	24			24
Short-term borrowings –affiliate, net	20			(2		)
Short-term borrowings, net	(44		)	105
Net Cash Provided From Financing Activities	201			145
Net Increase (Decrease) In Cash and Cash Equivalents	8			(7		)
Cash and Cash Equivalents, January 1	16			31
Cash and Cash Equivalents, March 31	$	24		$	24
Supplemental Cash Flow Information:
Cash paid for– Interest (net of capitalized interest of $2 and $2)	$	51		$	47
– Income taxes	—			—
Noncash Investing and Financing Activities:
Accrued construction expenditures	103			84

See Notes to Condensed Consolidated Financial Statements.

39

SOUTH CAROLINA ELECTRIC & GAS COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

For the Three Months Ended March 31, 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 $489 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, fossil fuel 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 Matter

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

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

2. RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric

SCE&G's retail electric rates are established in part by using a cost of fuel component approved by the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased by SCE&G. In February 2012, SCE&G requested authorization to decrease the total fuel cost component of its retail electric rates to be effective the first billing cycle of May 2012. On March 15, 2012, SCE&G, ORS and SCEUC entered into a settlement agreement in which SCE&G agreed to

40

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. By order dated April 24, 2012, the SCPSC approved the settlement agreement.

On July 15, 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 its annual update on DSM Programs and rate rider. By order dated May 24, 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 its annual update on DSM Programs and rate rider. By order dated April 25, 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 becomes 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.

    On November 15, 2010, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost schedule that, among other things, incorporated then-identifiable capital costs of $173.9 million (SCE&G's portion in 2007 dollars), and by order dated May 16, 2011, the SCPSC approved the updated capital costs schedule as outlined in the petition.

 On February 29, 2012, SCE&G filed a petition with the SCPSC seeking an order approving a further updated capital cost and construction schedule that incorporates additional identifiable capital costs of approximately of $6 million (SCE&G's portion in 2007 dollars) related to new federal healthcare laws, information security measures, and certain minor design modifications. That petition also includes increased capital costs of approximately $12 million (SCE&G's portion in 2007 dollars) related to transmission infrastructure. Finally, that petition includes amounts of approximately $137 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. That petition is expected to be recalled and replaced with a new petition which will include the costs arising from the resolution of the commercial claims discussed in Note 9 to the consolidated financial statements (e.g., those 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).

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

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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

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.

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	March 31, 2012		December 31, 2011
Regulatory Assets:
Accumulated deferred income taxes	$	238	$	238
Under collections – electric fuel adjustment clause	6		28
Environmental remediation costs	25		25
AROs and related funding	303		301
Franchise agreements	39		40
Deferred employee benefit plan costs	346		348
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	134		154
Deferred pollution control costs	29		25
Other	44		41
Total Regulatory Assets	$	1,164	$	1,206
Regulatory Liabilities:
Accumulated deferred income taxes	$	22	$	23
Asset removal costs	499		493
Storm damage reserve	31		32
Deferred gains on interest rate derivatives	37		24
Other	1		3
Total Regulatory Liabilities	$	590	$	575

Accumulated deferred income tax liabilities arising from utility operations that have not been included in customer rates are recorded as a regulatory asset.  Substantially all of these regulatory assets relate to depreciation and are expected to be recovered over the remaining lives of the related property which may range up to approximately 70 years.  Similarly, accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability.

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Under-collections - electric fuel adjustment clause represent amounts due from customers pursuant to the fuel adjustment clause as approved by the SCPSC during annual hearings which are expected to be recovered in retail electric rates by April 2013.  SCE&G is allowed to accrue interest on the base fuel deferred balances through the recovery period.

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 23 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 this purpose.  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 $9.3 million at March 31, 2012 and are being recovered through utility rates over approximately 30 years.  The remaining costs relate to Wateree Station, for which SCE&G will seek recovery in future proceedings 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 three months ended March 31, 2012 and 2011, SCE&G applied costs of $0.8 million and $0.7 million, respectively, to the reserve.  Pursuant to the SCPSC’s July 2010 retail electric rate order approving an electric rate increase, SCE&G suspended collection of the storm damage reserve indefinitely.

The SCPSC or the FERC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other regulatory assets include, but are not limited to, certain costs which have not been approved for recovery by the SCPSC or by FERC. In recording 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 three months ended March 31, 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	24			—			24
Dividends declared	(51		)	(2		)	(53		)
Comprehensive income	69			3			72
Balance as of March 31, 2012	$	3,707		$	109		$	3,816
Balance at January 1, 2011	$	3,437		$	104		$	3,541
Capital contribution from parent	24			—			24
Dividends declared	(49		)	(2		)	(51		)
Comprehensive income	68			2			70
Balance as of March 31, 2011	$	3,480		$	104		$	3,584

Authorized shares of SCE&G common stock were 50 million as of March 31, 2012 and December 31, 2011.  Outstanding shares of common stock were 40.3 million at both March 31, 2012 and December 31, 2011. Authorized shares of SCE&G preferred stock were 20 million as of March 31, 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 January 2012, SCE&G issued $250 million of 4.35% first mortgage bonds due February 1, 2042. Proceeds from the sale 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	March 31, 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)	$	468		$	512
Weighted average interest rate	0.50		%	0.56		%
Letters of credit supported by LOC	$	0.3		$	0.3
Available	$	632		$	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

44

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 the change in method of accounting for certain repair costs in prior years, 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 March 31, 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

SCE&G 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.  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 consolidated statements of cash flows.

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 1,010,000 DT at March 31, 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 $221.4 million at March 31, 2012 and $471.4 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 (a)	Value		Location (a)	Value
As of March 31, 2012
Derivatives designated as hedging instruments
Interest rate contracts				Other current liabilities	$	2
				Other deferred credits and other liabilities	55
Total					$	57
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

(a) Asset derivatives represent unrealized gains to Consolidated SCE&G, and liability derivatives represent unrealized losses. In Consolidated SCE&G’s condensed consolidated balance sheet, 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 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
Three Months Ended March 31, 2012
Interest rate contracts	$	30	Interest expense	$	(1	)
Three Months Ended March 31, 2011
Interest rate contracts	$	6	Interest expense	$	(1	)

	Gain (Loss) Recognized in Income
Derivatives Not Designated as
Hedging Instruments
Millions of dollars	Location	Amount
Three Months Ended March 31, 2012
Commodity contracts	Gas purchased for resale	$	(1	)
Three Months Ended March 31, 2011
Commodity contracts	Gas purchased for resale	$	(1	)

Hedge Ineffectiveness

Other gains (losses) recognized in income representing interest rate hedge ineffectiveness were insignificant for the three months ended March 31, 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 March 31, 2012 and December 31, 2011, Consolidated SCE&G has posted $39.1 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 March 31, 2012 and December 31, 2011, Consolidated SCE&G would be required to post an additional $17.8 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 March 31, 2012 and December 31, 2011 is $56.9 million and $76.7 million, respectively.

7. FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

SCE&G values commodity derivative assets and liabilities using unadjusted NYMEX prices to determine fair value, and considers such measure of fair value to be Level 1 for exchange traded instruments and Level 2 for over-the-counter instruments.  Consolidated SCE&G’s interest rate swap agreements are valued using discounted cashflow models with independently sourced market data.  Fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows: 

		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets	Significant Other Observable Inputs
Millions of dollars		(Level 1)	(Level 2)
Assets -	Interest rate contracts	—	—
Liabilities-	Interest rate contracts	—	$57
As of December 31, 2011
Assets -	Interest rate contracts	—	$1
Liabilities -	Interest rate contracts	—	77

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 March 31, 2012 and December 31, 2011 were as follows:

	March 31, 2012				December 31, 2011
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	3,482.6	$	4,126.3	$	3,241.5	$	3,920.3

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

8. EMPLOYEE BENEFIT PLANS

Pension and Other Postretirement Benefit Plans

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

	Pension Benefits						Other Postretirement Benefits
Millions of dollars	2012			2011			2012		2011
Three months ended March 31,
Service cost	$	3.9		$	3.7		$	1.0	$	0.9
Interest cost	9.1			9.4			2.4		2.4
Expected return on assets	(12.6		)	(13.8		)	—		—
Prior service cost amortization	1.4			1.5			0.2		0.2
Amortization of actuarial loss	4.0			2.6			0.1		—
Net periodic benefit cost	$	5.8		$	3.4		$	3.7	$	3.5

No contribution to the pension trust will be necessary in or for 2012, nor will limitations on benefit payments apply.   As authorized by the SCPSC, SCE&G defers all pension expense or income related to retail electric and gas operations as a regulatory asset or liability, as applicable. Costs totaling $3.7 million and $2.3 million were deferred for the three months ended March 31, 2012 and 2011, respectively.  

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

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.

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 2014 and will cost an additional $8.1 million, which is accrued in Other within Deferred Credits and Other Liabilities on the consolidated balance sheet.  SCE&G expects to recover any cost arising from the remediation of MGP sites through rates and insurance settlements.  At March 31, 2012, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $24.5 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 0.55 percent of the cost and receiving 0.55 percent of the output, and Santee Cooper responsible for and receiving the remaining 0.45 percent.  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 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, including those 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.  These issues resulted in assertions of contractual entitlement to recover additional costs to be incurred. On March 29, 2012, SCE&G and the Consortium signed a preliminary agreement which set SCE&G's portion of these costs 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 included in future rate filings and will be recoverable.

On February 29, 2012, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost and construction schedule that incorporates 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. That petition also includes increased capital costs of approximately $12 million (SCE&G's portion in 2007 dollars) related to transmission infrastructure. Finally, that petition includes amounts of approximately $137 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. It is anticipated that this petition will be recalled and replaced with a new petition which will also include the $138 million of additional costs referred to above.

Schedule changes identified in connection with COL delays, as well as the additional costs described above, are likely to result in changes to the amounts and timing of capital expenditures to be reflected in future quarterly reports to the SCPSC under the BLRA and in annual rate filings.  The results of an evaluation of the impact of certain of these changes are expected to be identified in the quarterly report to be filed on May 15, 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 $10.0 million and $7.9 million for the three months ended March 31, 2012 and 2011, respectively.  SCE&G had approximately $3.1 million and $2.5 million payable to CGT for transportation services at March 31, 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 $25.4 million and $45.4 million for the three months ended March 31, 2012 and 2011, respectively.  SCE&G’s payables to SEMI for such purposes were $3.5 million and $13.2 million as of March 31, 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 $8.7 million at March 31, 2012 and $8.5 million at December 31, 2011.  SCE&G’s payables to these affiliates were $8.8 million at March 31, 2012 and $8.6 million at December 31, 2011.  SCE&G’s total purchases were $27.1 million and $13.0 million for the three months ended March 31, 2012 and 2011, respectively.  SCE&G’s total sales were $26.9 million and $12.9 million for the three months ended March 31, 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 three months ended March 31, 2012 or 2011.  At March 31, 2012 and December 31, 2011, Consolidated SCE&G owed an affiliate $78.6 million and $58.5 million, respectively.

11. SEGMENT OF BUSINESS INFORMATION

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

	External		Operating Income			Earnings Available to Common		Segment
Millions of Dollars	Revenue		(Loss)			Shareholder		Assets
Three Months Ended March 31, 2012
Electric Operations	$	547	$	127		n/a		$	8,449
Gas Distribution	116		29			n/a		627
Adjustments/Eliminations	—		—			$	69	2,140
Consolidated Total	$	663	$	156		$	69	$	11,216
Three Months Ended March 31, 2011
Electric Operations	$	560	$	122		n/a		$	8,002
Gas Distribution	144		30			n/a		587
Adjustments/Eliminations	—		(1		)	$	68	1,946
Consolidated Total	$	704	$	151		$	68	$	10,535

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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 MONTHS ENDED MARCH 31, 2012

AS COMPARED TO THE CORRESPONDING PERIOD IN 2011

Net Income

Net income for Consolidated SCE&G was as follows:

Millions of dollars	2012		% Change		2011
Net income	$	71.6	1.8	%	70.3

Net income increased by higher electric margin of $9.3 million.  This increase was partially offset by $3.9 million due to higher operation and maintenance expenses, higher depreciation expense of $1.6 million, higher property taxes of $0.6 million and higher interest expense of $0.6 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

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:

Millions of dollars		2012		% Change		2011
Operating revenues		$	547.4	(2.3	)%	$	560.3
Less:	Fuel used in electric generation	182.7		(14.1	)%	212.6
	Purchased power	5.7		147.8	%	2.3
Margin		$	359.0	3.9	%	$	345.4

Margin increased primarily due to $12.7 million increase in base rates approved by the SCPSC under the BLRA.

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

Classification	2012	% Change		2011
Residential	1,691	(17.8	)%	2,058
Commercial	1,644	(0.4	)%	1,650
Industrial	1,385	(2.2	)%	1,416
Other	135	6.3	%	127
Total Retail Sales	4,855	(7.5	)%	5,251
Wholesale	634	31.8	%	481
Total Sales	5,489	(4.2	)%	5,732

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

Millions of dollars	2012		% Change		2011
Operating revenues	$	115.7	(19.7	)%	$	144.1
Less: Gas purchased for resale	59.2		(32.6	)%	87.8
Margin	$	56.5	0.4	%	$	56.3

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

Classification (in thousands)	2012	% Change		2011
Residential	4,619	(29.3	)%	6,532
Commercial	3,579	(16.3	)%	4,277
Industrial	4,843	8.4	%	4,467
Transportation	1,304	9.4	%	1,192
Total	14,345	(12.9	)%	16,468

Total sales volumes decreased primarily due to lower firm customer usage as a result of milder weather.

Other Operating Expenses

Other operating expenses were as follows:

Millions of dollars	2012		% Change		2011
Other operation and maintenance	$	138.4	4.8	%	$	132.0
Depreciation and amortization	73.1		3.1	%	70.9
Other taxes	47.7		0.6	%	47.4

Other operation and maintenance expenses increased by $6.7 million due to higher generation, transmission and distribution expenses, by $0.7 due to higher compensation and benefits and by $2.0 million due to higher 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.

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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) as noncash items, 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 tax rate) for the three months ended March 31, 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, as well as by the recognition of certain previously deferred state income tax credits which were higher in 2011.

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 three and 12 months ended March 31, 2012 was 2.98 and 3.14, respectively.

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	March 31, 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)	$	468		$	512
Weighted average interest rate	0.50		%	0.56		%
Letters of credit supported by LOC	$	0.3		$	0.3
Available	$	632		$	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.

At March 31, 2012, Consolidated SCE&G had net available liquidity of approximately $656.0 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, while maintaining appropriate levels of liquidity.  Consolidated SCE&G’s long term debt portfolio has a weighted average maturity of approximately 19 years and bears an average 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 January 2012, SCE&G issued $250 million of 4.35% first mortgage bonds due February 1, 2042. Proceeds from the sale 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 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 percent of the cost and receiving 55 percent of the output, and Santee Cooper responsible for and receiving the remaining 45 percent.  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 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, including those 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.  These issues resulted in assertions of contractual entitlement to recover additional costs to be incurred. On March 29, 2012, SCE&G and the Consortium signed a preliminary agreement which set SCE&G's portion of these costs 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 included in future rate filings and will be recoverable through rates.

On February 29, 2012, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost and construction schedule that incorporates 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. That petition also includes increased capital costs of approximately $12 million (SCE&G's portion in 2007 dollars) related to transmission infrastructure. Finally, that petition includes amounts of approximately $137 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. It is anticipated that this petition will be recalled and replaced with a new petition which will include the $138 million of additional costs referred to above.

Schedule changes identified in connection with COL delays, as well as the additional costs described above, are likely to result in changes to the amounts and timing of capital expenditures to be reflected in future quarterly reports to the SCPSC

50

under the BLRA and in annual rate filings.  The results of an evaluation of the impact of certain of these changes are expected to be identified in the quarterly report to be filed on May 15, 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 - 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.

Commodity price risk - SCE&G uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types.  See Note 6 of the condensed consolidated financial statements.  The following table provides information about SCE&G’s financial instruments that are sensitive to changes in natural gas prices.  Weighted average settlement prices are per 10,000 DT.  Fair value represents quoted market prices for these or similar instruments.

Expected Maturity:
Options
	Purchased Call
2012	(Long)
Strike Price (a)	4.17
Contract Amount (b)	4.2
Fair Value (b)	—

(a) Weighted average, in dollars

(b) Millions of dollars

51

ITEM 4. CONTROLS AND PROCEDURES

As of March 31, 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 March 31, 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 March 31, 2012, that has materially affected or is reasonably likely to materially affect SCE&G’s internal control over financial reporting.

52

PART II.  OTHER INFORMATION

ITEM 6. EXHIBITS

SCANA and SCE&G:

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

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

53

SIGNATURES

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

SCANA CORPORATION

SOUTH CAROLINA ELECTRIC & GAS COMPANY

(Registrants)

	By:	/s/James E. Swan, IV
Date: May 4, 2012		James E. Swan, IV
		Controller
		(Principal accounting officer)

54

EXHIBIT INDEX

	Applicable to Form 10-Q of
Exhibit No.	SCANA	SCE&G	Description
3.01	X		Restated Articles of Incorporation of SCANA, as adopted on April 26, 1989 (Filed as Exhibit 3-A to Registration Statement No. 33-49145 and incorporated by reference herein)
3.02	X		Articles of Amendment dated April 27, 1995 (Filed as Exhibit 4-B to Registration Statement No. 33-62421 and incorporated by reference herein)
3.03	X		Articles of Amendment effective April 25, 2011 (Filed as Exhibit 4.03 to Registration Statement No. 333-174796 and incorporated by reference herein)
3.04		X	Restated Articles of Incorporation of SCE&G, as adopted on December 30, 2009 (Filed as Exhibit 1 to Form 8-A (File Number 000-53860) and incorporated by reference herein)
3.05	X		By-Laws of SCANA as amended and restated as of February 19, 2009 (Filed as Exhibit 4.04 to Registration Statement No. 333-174796 and incorporated by reference herein)
3.06		X	By-Laws of SCE&G as revised and amended on February 22, 2001 (Filed as Exhibit 3.05 to Registration Statement No. 333-65460 and incorporated by reference herein)
31.01	X		Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)
31.02	X		Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)
31.03		X	Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)
31.04		X	Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)
32.01	X		Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
32.02	X		Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
32.03		X	Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
32.04		X	Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
101. INS*	X	X	XBRL Instance Document
101. SCH*	X	X	XBRL Taxonomy Extension Schema
101. CAL*	X	X	XBRL Taxonomy Extension Calculation Linkbase
101. DEF*	X	X	XBRL Taxonomy Extension Definition Linkbase
101. LAB*	X	X	XBRL Taxonomy Extension Label Linkbase
101. PRE*	X	X	XBRL Taxonomy Extension Presentation Linkbase

*   Pursuant to Rule 406T of Regulation S-T, this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.

55

EX-31.01

Exhibit 31.01

CERTIFICATION

I, Kevin B. Marsh, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: May 4, 2012
	/s/Kevin B. Marsh
	Kevin B. Marsh
	Chairman of the Board, President, Chief Executive Officer and
	Chief Operating Officer

62

EX-31.02

Exhibit 31.02

CERTIFICATION

I, Jimmy E. Addison, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: May 4, 2012
	/s/Jimmy E. Addison
	Jimmy E. Addison
	Executive Vice President and Chief Financial Officer

63

EX-31.03

Exhibit 31.03

CERTIFICATION

I, Kevin B. Marsh, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: May 4, 2012
	/s/Kevin B. Marsh
	Kevin B. Marsh
	Chairman of the Board and Chief Executive Officer

63

EX-31.04

Exhibit 31.04

CERTIFICATION

I, Jimmy E. Addison, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: May 4, 2012
	/s/Jimmy E. Addison
	Jimmy E. Addison
	Executive Vice President and Chief Financial Officer

64

EX-32.01

Exhibit 32.01

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of SCANA Corporation (the “Company”) on Form 10-Q for the quarter ended March 31, 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: May 4, 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. 

65

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 March 31, 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: May 4, 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. 

66

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 March 31, 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: May 4, 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. 

67

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 March 31, 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: May 4, 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. 

68

XML

DERIVATIVE FINANCIAL INSTRUMENTS (Details) (USD $)	Mar. 31, 2012		Dec. 31, 2011
Derivative [Line Items]
Commodity and other energy management contracts designated as cash flow hedges (in DT)	31,733,275		36,427,763
Nonmonetary Notional Amount of Price Risk Derivative Instruments Not Designated as Hedging Instruments	40,527,609	[1]	41,023,563	[2]
Commodity and other energy management contracts (in DT)	72,260,884	[1]	77,451,326	[2]
Commodity and other energy management contracts not designated as hedges (in DT)	8,694,000		9,626,000
Aggregate notional amount of interest rate swaps designated as fair value hedge (in dollars)	$ 0		$ 0
Aggregate notional amount of interest rate swaps designated as cash flow hedge (in dollars)	$ 322.6		$ 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	10,100,000		9,080,000
Commodity and other energy management contracts (in DT)	10,100,000		9,080,000
Retail Gas Marketing
Derivative [Line Items]
Commodity and other energy management contracts designated as cash flow hedges (in DT)	4,141,000		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)	4,141,000		6,566,000
Energy Marketing
Derivative [Line Items]
Commodity and other energy management contracts designated as cash flow hedges (in DT)	27,592,275		29,861,763
Nonmonetary Notional Amount of Price Risk Derivative Instruments Not Designated as Hedging Instruments	30,427,609	[1]	31,943,563	[2]
Commodity and other energy management contracts (in DT)	58,019,884	[1]	61,805,326	[2]

[1] (a) Includes an aggregate 8,694,000 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
	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011
Segment Reporting Information [Line Items]
External Revenue	$ 1,107	$ 1,281
Intersegment Revenue	0	0
Operating Income	238	248
Income Available to Common Shareholders of SCANA	121	128
Segment Assets	13,580	12,873	13,534
Electric Operations
Segment Reporting Information [Line Items]
External Revenue	545	558
Intersegment Revenue	2	2
Operating Income	127	122
Segment Assets	8,449	8,002
Gas Distribution
Segment Reporting Information [Line Items]
External Revenue	274	360
Intersegment Revenue	0	0
Operating Income	83	84
Segment Assets	2,277	2,177
Retail Gas Marketing
Segment Reporting Information [Line Items]
External Revenue	153	202
Intersegment Revenue	0	0
Income Available to Common Shareholders of SCANA	11	22
Segment Assets	157	201
Energy Marketing
Segment Reporting Information [Line Items]
External Revenue	132	158
Intersegment Revenue	26	45
Income Available to Common Shareholders of SCANA	2	1
Segment Assets	95	95
All Other
Segment Reporting Information [Line Items]
External Revenue	11	10
Intersegment Revenue	106	102
Operating Income	7	5
Income Available to Common Shareholders of SCANA	5	1
Segment Assets	1,337	1,262
Adjustments/Eliminations
Segment Reporting Information [Line Items]
External Revenue	(8)	(7)
Intersegment Revenue	(134)	(149)
Operating Income	21	37
Income Available to Common Shareholders of SCANA	103	104
Segment Assets	$ 1,265	$ 1,136

XML

RATE AND OTHER REGULATORY MATTERS (Details 2) (USD $) In Millions, unless otherwise specified	1 Months Ended		3 Months Ended	24 Months Ended
	Feb. 29, 2012	Nov. 30, 2010	Mar. 31, 2012	Jul. 31, 2012	Dec. 31, 2011
Regulatory Assets:
Public Utilities, Property, Plant and Equipment Identifiable Capital Costs	$ 6	$ 0
Share in Approved Capital Costs	12
Public Utilities Additional Labor Expenses for Oversight of New Units	137
Regulatory assets			1,237.0		1,279.0
Regulatory assets, expected recovery period (in years)			30
Amount Recovered Through Electric Rates to Offset Turbine Expenses				18.4
Accrual period of nuclear refueling charges (in months)			18
Deferred Income Tax Charges [Member]
Regulatory Assets:
Regulatory assets			243.0		243.0
Regulatory assets, expected recovery period (in years)			70
Under-collections-electric fuel adjustment clause
Regulatory Assets:
Regulatory assets			6.0		28.0
Environmental remediation costs
Regulatory Assets:
Regulatory assets			30.0		30.0
Regulatory assets, expected recovery period (in years)			23
Asset Retirement Obligation Costs [Member]
Regulatory Assets:
Regulatory assets			319.0		316.0
Regulatory assets, expected recovery period (in years)			95
Franchise agreements
Regulatory Assets:
Regulatory assets			39.0		40.0
Regulatory assets, expected recovery period (in years)			20
Deferred employee benefit plan costs
Regulatory Assets:
Regulatory assets			390.0		392.0
Regulatory assets, expected recovery period (in years)			12
Planned major maintenance
Regulatory Assets:
Regulatory assets			0		6.0
Deferred losses on interest rate derivatives
Regulatory Assets:
Regulatory assets			134.0		154.0
Regulatory assets, expected recovery period (in years)			30
Deferred pollution control costs
Regulatory Assets:
Regulatory assets			29.0		25.0
Other.
Regulatory Assets:
Regulatory assets			47.0		45.0
Regulatory assets, expected recovery period (in years)			30
SCE&G
Regulatory Assets:
Regulatory assets			$ 1,164.0		$ 1,206.0

XML

COMMON EQUITY (Tables)

3 Months Ended

Mar. 31, 2012

Stockholders' Equity Note [Abstract]

Schedule of Stockholders Equity [Table Text Block]

Changes in common equity during the three months ended March 31, 2012 and 2011 were as follows:

Millions of dollars	2012			2011
Balance at January 1,	$	3,889		$	3,702
Common stock issued	26			25
Dividends declared	(65		)	(62		)
Comprehensive income	127			135
Balance as of March 31,	$	3,977		$	3,800

XML

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details) (USD $)	Mar. 31, 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
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	1,000,000	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	2,000,000	1,000,000
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other energy management contracts
Assets, Fair Value Disclosure [Abstract]
Derivative Assets	0	0
Liabilities, Fair Value Disclosure [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	3,000,000	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		2,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	85,000,000	158,000,000
Fair Value, Inputs, Level 2 [Member] | Commodity contracts
Assets, Fair Value Disclosure [Abstract]
Derivative Assets	1,000,000	1,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	9,000,000	13,000,000
Fair Value, Inputs, Level 2 [Member] | Other energy management contracts
Assets, Fair Value Disclosure [Abstract]
Derivative Assets	31,000,000	27,000,000
Liabilities, Fair Value Disclosure [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	$ 29,000,000	$ 26,000,000

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LONG-TERM AND SHORT-TERM DEBT (Details 2) (USD $) In Millions, unless otherwise specified																								3 Months Ended
	Mar. 31, 2012	Mar. 31, 2012 PSNC Energy	Mar. 31, 2012 SCE&G (including Fuel Company)	Mar. 31, 2012 Fuel Company	Mar. 31, 2012 Parent Company [Member]	Mar. 31, 2012 Wells Fargo Bank, National Association (Member)	Mar. 31, 2012 Bank of America, N.A. (Member)	Mar. 31, 2012 Morgan Stanly Bank, N.A. (Member)	Mar. 31, 2012 Branch Banking and Trust Company (Member)	Mar. 31, 2012 Credit Suisse AG, Cayman Islands Branch (Member)	Mar. 31, 2012 JPMorgan Chase Bank, N.A. (Member)	Mar. 31, 2012 Mizuho Corporate Bank, Ltd (Member)	Mar. 31, 2012 TD Bank, N.A. (Member)	Mar. 31, 2012 UBS Loan Finance LLC (Member)	Mar. 31, 2012 Deutsche Bank AG, New York Branch (Member)	Mar. 31, 2012 Union Bank, N.A. (Member)	Mar. 31, 2012 US Bank National Association (Member)	Mar. 31, 2012 Parent Company [Member]	Dec. 31, 2011 Parent Company [Member]	Mar. 31, 2012 SCE&G (including Fuel Company)	Dec. 31, 2011 SCE&G (including Fuel Company)	Mar. 31, 2012 PSNC Energy	Dec. 31, 2011 PSNC Energy	Mar. 31, 2012 First Mortgage Bonds [Member]	Mar. 31, 2012 Medium Term Notes First [Member]	Mar. 31, 2012 Medium-term Notes [Member]
Debt Instruments [Abstract]
Debt Instrument, Increase, Additional Borrowings																								$ 250	$ 250
Debt Instrument, Interest Rate, Stated Percentage																								4.35%	4.125%	6.25%
Debt Instrument, Decrease, Repayments																									250
Face value of Industrial Revenue Bonds issued, proceeds of which were availed as loan	67.8
Lines of credit:
Committed long-term line of credit, Total	1,500	100	1,100	400	300													300	300	1,100	1,100	100	100
Outstanding commercial paper (270 or fewer days)																		117	131	468	512	0	10
Commercial paper, weighted average interest rate (as a percent)																		0.85%	0.63%	0.50%	0.56%	0.00%	0.57%
Letters of credit supported by LOC																		3.0	3.0	0.3	0.3	0	0
Available amount under lines of credit																		180	166	632	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%
Number of other banks (in entities)	3

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CONSOLIDATED STATEMENTS OF CASH FLOWS (Parentheticals) (USD $)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Cash paid for interest, capitalized interest	$ 2	$ 2
SCE&G
Cash paid for interest, capitalized interest	$ 2	$ 2

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FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details 2) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Carrying Amount
Financial instruments for which the carrying amount may not equal estimated fair value
Long-term debt	$ 4,891.9	$ 4,653.0
Estimated Fair Value
Financial instruments for which the carrying amount may not equal estimated fair value
Long-term debt	$ 5,669.6	$ 5,479.2

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EMPLOYEE BENEFIT PLANS (Tables)

3 Months Ended

Mar. 31, 2012

Compensation and Retirement Disclosure [Abstract]

Components of Net Periodic Benefit Cost (Income)

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 March 31,
Service cost	$	4.8		$	4.6		$	1.3	$	1.1
Interest cost	10.7			11.1			3.0		3.0
Expected return on assets	(14.8		)	(16.2		)	—		—
Prior service cost amortization	1.7			1.8			0.2		0.3
Transition obligation amortization	—			—			0.2		0.2
Amortization of actuarial loss	4.7			3.0			0.2		0.1
Net periodic benefit cost	$	7.1		$	4.3		$	4.9	$	4.7

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FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Tables)

3 Months Ended

Mar. 31, 2012

Fair Value Disclosures [Abstract]

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 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)
Assets -	Available for sale securities	$	8	—
	Energy management contracts	—		$	31
	Commodity contracts	1		1
Liabilities -	Interest rate contracts	—		85
	Commodity contracts	2		9
	Energy management contracts	3		29
As of December 31, 2011
Assets -	Available for sale securities	$	3	—
	Interest rate contracts	—		$	2
	Commodity contracts	—		1
	Energy management contracts	—		27
Liabilities -	Interest rate contracts	—		158
	Commodity contracts	1		13
	Energy management contracts	—		26

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

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

	March 31, 2012				December 31, 2011
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	4,891.9	$	5,669.6	$	4,653.0	$	5,479.2

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EMPLOYEE BENEFIT PLANS (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Components of Net Periodic Benefit Cost
Pension Costs Related to Retail Electric Operations and Natural Gas Operations Deferred as Regulatory Assets	$ 3.7	$ 2.3
Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	4.8	4.6
Interest cost	10.7	11.1
Expected return on assets	(14.8)	(16.2)
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax	1.7	1.8
Defined Benefit Plan, Amortization of Transition Obligations (Assets)	0	0
Defined Benefit Plan, Actuarial Net (Gains) Losses	4.7	3.0
Defined Benefit Plan, Net Periodic Benefit Cost	7.1	4.3
Other Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	1.3	1.1
Interest cost	3.0	3.0
Expected return on assets	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	0.3
Defined Benefit Plan, Amortization of Transition Obligations (Assets)	0.2	0.2
Defined Benefit Plan, Actuarial Net (Gains) Losses	0.2	0.1
Defined Benefit Plan, Net Periodic Benefit Cost	$ 4.9	$ 4.7

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SEGMENT OF BUSINESS INFORMATION (Tables)

3 Months Ended

Mar. 31, 2012

Segment Reporting [Abstract]

Schedule of revenue, income and assets by segments

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		Segment
Millions of dollars	Revenue			Revenue			Income		Income		Assets
Three Months Ended March 31, 2012
Electric Operations	$	545		$	2		$	127	n/a		$	8,449
Gas Distribution	274			—			83		n/a		2,277
Retail Gas Marketing	153			—			n/a		$	11	157
Energy Marketing	132			26			n/a		2		95
All Other	11			106			7		5		1,337
Adjustments/Eliminations	(8		)	(134		)	21		103		1,265
Consolidated Total	$	1,107		$	—		$	238	$	121	$	13,580
Three Months Ended March 31, 2011
Electric Operations	$	558		$	2		$	122	n/a		$	8,002
Gas Distribution	360			—			84		n/a		2,177
Retail Gas Marketing	202			—			n/a		$	22	201
Energy Marketing	158			45			n/a		1		95
All Other	10			102			5		1		1,262
Adjustments/Eliminations	(7		)	(149		)	37		104		1,136
Consolidated Total	$	1,281		$	—		$	248	$	128	$	12,873

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 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)	27.00%		45.00%
Natural gas inventory, carrying amount	$ 10.9		$ 28.7
Earnings Per Share
Weighted Average Shares Outstanding - Basic	130.3	127.9
Incremental Common Shares Attributable to Share-based Payment Arrangements and Equity Forward Agreements	1.9	1.1
Weighted Average Number of Shares Outstanding, Diluted	132.2	129.0

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Cash Flows From Operating Activities:
Income Available to Common Shareholders of SCANA	$ 121	$ 128
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	50	11
Depreciation and amortization	92	88
Amortization of nuclear fuel	13	9
Allowance for equity funds used during construction	(3)	(3)
Cash provided (used) by changes in certain assets and liabilities:
Receivables	65	192
Inventories	(11)	17
Prepayments and other	68	83
Regulatory liabilities	1	(2)
Accounts payable	(18)	(146)
Taxes accrued	(101)	(99)
Interest accrued	(1)	0
Regulatory assets	41	14
Changes in other assets	(43)	0
Changes in other liabilities	(89)	(52)
Net Cash Provided From Operating Activities	185	241
Cash Flows From Investing Activities:
Property additions and construction expenditures	(321)	(295)
Proceeds from investments (including derivative collateral posted)	151	1
Purchase of investments (including derivative collateral posted)	(109)	(6)
Payments for (Proceeds from) Hedge, Investing Activities	13	0
Payments for interest rate contract settlements	(51)	0
Net Cash Used in Investing Activities	(317)	(300)
Cash Flows From Financing Activities:
Proceeds from Issuance of Common Stock	26	25
Proceeds from issuance of long-term debt	494	379
Repayments of Long-term Debt	(259)	(309)
Dividends	(63)	(61)
Short-term borrowings, net	(68)	92
Net Cash Provided From Financing Activities	130	126
Net (Decrease) Increase in Cash and Cash Equivalents	(2)	67
Cash and Cash Equivalents, January 1	29	55
Cash and Cash Equivalents, March 31	27	122
Supplemental Cash Flow Information:
Cash paid for-Interest (net of capitalized interest of $2 and $2)	74	67
Cash paid for-Income taxes	0	0
Noncash Investing and Financing Activities:
Accrued construction expenditures	108	93
SCE&G
Cash Flows From Operating Activities:
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	72	70
Adjustments to reconcile net income to net cash provided from operating activities:
Losses from equity method investments	1	0
Deferred income taxes, net	44	8
Depreciation and amortization	73	74
Amortization of nuclear fuel	13	9
Allowance for equity funds used during construction	(3)	(3)
Cash provided (used) by changes in certain assets and liabilities:
Receivables	28	107
Inventories	(38)	(13)
Prepayments and other	2	59
Regulatory liabilities	1	(1)
Accounts payable	15	(67)
Taxes accrued	(80)	(96)
Interest accrued	(3)	(2)
Regulatory assets	41	13
Changes in other assets	(1)	(4)
Changes in other liabilities	(78)	(36)
Net Cash Provided From Operating Activities	87	118
Cash Flows From Investing Activities:
Property additions and construction expenditures	(295)	(269)
Proceeds from investments (including derivative collateral posted)	52	1
Purchase of investments (including derivative collateral posted)	(50)	(2)
Payments for (Proceeds from) Hedge, Investing Activities	13	0
Net Cash Used in Investing Activities	(280)	(270)
Cash Flows From Financing Activities:
Proceeds from issuance of long-term debt	248	229
Repayments of Long-term Debt	(8)	(157)
Dividends	(39)	(54)
Contributions from parent	24	24
Short-term borrowings, net	(44)	105
Short-term borrowings- affiliate,net	20	(2)
Net Cash Provided From Financing Activities	201	145
Net (Decrease) Increase in Cash and Cash Equivalents	8	(7)
Cash and Cash Equivalents, January 1	16	31
Cash and Cash Equivalents, March 31	24	24
Supplemental Cash Flow Information:
Cash paid for-Interest (net of capitalized interest of $2 and $2)	51	47
Cash paid for-Income taxes	0	0
Noncash Investing and Financing Activities:
Accrued construction expenditures	$ 103	$ 84

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RATE AND OTHER REGULATORY MATTERS (Details) (USD $)	1 Months Ended		3 Months Ended		12 Months Ended			24 Months Ended
	Feb. 29, 2012	Nov. 30, 2010	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011	Jul. 31, 2011	Dec. 31, 2010	Jul. 31, 2012	May 01, 2012
Rate Matters [Line Items]
Amount Recovered Through Electric Rates to Offset Deferred Pollution, Control Costs			$ 9,300,000
Increase in retail electric rates (as a percent)						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	6,000,000	0
Public Utilities Additional Labor Expenses for Oversight of New Units	137,000,000
Public Utilities Percent Increase (Decrease) in Retail Electric Rates Requested and Approved Under BLRA					2.40%		2.30%
Increase (decrease) in retail electric rate requested under the BLRA					52.8		47.3
Percentage increase (decrease) in natural gas retail rates under the RSA (as a percent)					2.10%		(2.10%)
Increase (decrease) in natural gas retail rates under the RSA					8.6		10.4
Basis for rate calculation			12-month rolling average		12
Certain charges reassigned from cost of gas for which motion request filed by Public Staff of the NCUC			$ 400,000
Public Utilities, Increase (Decrease) in Cost of Gas Component of Retail Natural Gas Rates			0
Regulatory Noncurrent Asset, Amortization Period			30

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DERIVATIVE FINANCIAL INSTRUMENTS (Details 2) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Derivatives designated as hedging instruments
Derivative [Line Items]
Asset Derivatives Fair Value	$ 2	$ 3	[1]
Liability Derivatives Fair Value	96	172
Derivatives designated as hedging instruments | Interest Rate Contract | Prepayments and other
Derivative [Line Items]
Asset Derivatives Fair Value	0	2
Derivatives designated as hedging instruments | Interest Rate Contract | Other current liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	5	55
Derivatives designated as hedging instruments | Interest Rate Contract | Other deferred credits and other liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	80	103
Derivatives designated as hedging instruments | Commodity contracts | Prepayments and other
Derivative [Line Items]
Asset Derivatives Fair Value	1
Liability Derivatives Fair Value	2	1
Derivatives designated as hedging instruments | Commodity contracts | Other current liabilities
Derivative [Line Items]
Asset Derivatives Fair Value	1	1	[1]
Liability Derivatives Fair Value	7	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	31	27
Liability Derivatives Fair Value	30	25
Derivatives not designated as hedging instruments | Other Energy Management Contract [Member] | Prepayments and other
Derivative [Line Items]
Asset Derivatives Fair Value	19	17
Liability Derivatives Fair Value	3	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	12	10
Derivatives not designated as hedging instruments | Other Energy Management Contract [Member] | Other current liabilities
Derivative [Line Items]
Liability Derivatives Fair Value	16	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	$ 11	$ 9

[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	Mar. 31, 2012	Dec. 31, 2011
Assets
Utility Plant In Service	$ 12,071	$ 12,000
Accumulated Depreciation and Amortization	(3,898)	(3,836)
Construction Work in Progress	1,694	1,482
Nuclear Fuel, Net of Accumulated Amortization	158	171
Goodwill, Net of Writedown of $230	230	230
Utility Plant, Net	10,255	10,047
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation of $131 and $118	304	305
Assets held in trust, net-nuclear decommissioning	87	84
Other investments	94	87
Nonutility Property and Investments, Net	485	476
Current Assets:
Cash and cash equivalents	27	29
Receivables, net of allowance for uncollectible accounts of $6 and $9	715	756
Inventories (at average cost):
Fuel	312	313
Materials and supplies	128	129
Emission allowances	2	2
Prepayments and other	153	236
Deferred income taxes	22	26
Total Current Assets	1,359	1,491
Deferred Debits and Other Assets:
Regulatory assets	1,237.0	1,279.0
Other	244	241
Total Deferred Debits and Other Assets	1,481	1,520
Total	13,580	13,534
Capitalization and Liabilities
Common equity	3,977	3,889
Long-Term Debt, Net	4,862	4,622
Total Capitalization	8,839	8,511
Current Liabilities:
Short-term borrowings	585	653
Current portion of long-term debt	30	31
Accounts payable	342	374
Customer deposits and customer prepayments	95	103
Taxes accrued	53	154
Interest accrued	73	74
Dividends declared	65	63
Derivative financial instruments	27	77
Other	75	113
Total Current Liabilities	1,345	1,642
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,583	1,533
Deferred investment tax credits	39	40
Asset retirement obligations	479	474
Pension and other postretirement benefits	293	291
Regulatory liabilities	797	778
Other	205	265
Total Deferred Credits and Other Liabilities	3,396	3,381
Commitments and Contingencies (Note 9)	0	0
Total	13,580	13,534
SCE&G
Assets
Utility Plant In Service	10,376	10,312
Accumulated Depreciation and Amortization	(3,425)	(3,367)
Construction Work in Progress	1,679	1,472
Nuclear Fuel, Net of Accumulated Amortization	158	171
Utility Plant, Net	8,788	8,588
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation of $131 and $118	53	52
Assets held in trust, net-nuclear decommissioning	87	84
Other investments	5	2
Nonutility Property and Investments, Net	145	138
Current Assets:
Cash and cash equivalents	24	16
Receivables, net of allowance for uncollectible accounts of $6 and $9	478	482
Due from Affiliate, Current	9	9
Inventories (at average cost):
Fuel	222	196
Materials and supplies	119	120
Emission allowances	2	2
Prepayments and other	79	82
Deferred income taxes	7	8
Total Current Assets	940	915
Deferred Debits and Other Assets:
Regulatory assets	1,164.0	1,206.0
Other	180	190
Total Deferred Debits and Other Assets	1,344	1,396
Total	11,217	11,037
Capitalization and Liabilities
Common equity	3,707	3,665
Stockholders' Equity Attributable to Noncontrolling Interest	109	108
Long-Term Debt, Net	3,464	3,222
Total Capitalization	7,280	6,995
Current Liabilities:
Short-term borrowings	468	512
Current portion of long-term debt	19	19
Accounts payable	252	231
Due to Affiliate, Current	143	136
Customer deposits and customer prepayments	51	54
Taxes accrued	70	150
Interest accrued	51	54
Dividends declared	53	39
Derivative financial instruments	2	2
Other	37	61
Total Current Liabilities	1,146	1,258
Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,414	1,371
Deferred investment tax credits	39	40
Asset retirement obligations	455	449
Pension and other postretirement benefits	181	179
Regulatory liabilities	590	575
Other	112	170
Total Deferred Credits and Other Liabilities	2,791	2,784
Commitments and Contingencies (Note 9)	0	0
Total	$ 11,217	$ 11,037

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COMMITMENTS AND CONTINGENCIES (Details) (USD $)	1 Months Ended		3 Months Ended	12 Months Ended
	Feb. 29, 2012	Nov. 30, 2010	Mar. 31, 2012	Dec. 31, 2011	Dec. 31, 2005
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
Maximum liability assessment per reactor for each nuclear incident			117,500,000	78,300,000
Maximum yearly assessment per reactor			17,500,000
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
Maximum amount of coverage for accidental property damage			500,000,000
Environmental
Number of states required to reduce emissions to attain mandated levels					28
Regulatory assets			1,237,000,000	1,279,000,000
Nuclear Generation
Number of nuclear electric generation units			2
Generation capacity (in MW)			1,117
Percentage applicable to the Company (as a percent)			55.00%
Percentage applicable to joint owner 2 (as a percent)			45.00%
Estimated cash outflow for plant costs and related transmission infrastructure costs of nuclear electric generation site			6,000,000,000
Public Utilities, Property, Plant and Equipment Identifiable Capital Costs	6,000,000	0
Share in Approved Capital Costs	12,000,000
Public Utilities Additional Labor Expenses for Oversight of New Units	137,000,000
SCE&G
Environmental
Number of MGP decommissioned sites that contain residues of by-product chemicals			4
Additional costs to be incurred for remediation			8,100,000
Deferred costs, net of costs previously recovered through rates and insurance settlements included in regulatory assets			24,500,000
Regulatory assets			1,164,000,000	1,206,000,000
Nuclear Generation
Jointly Owned Utility Plant, Minimum Period for which Escalation Rates are Considered to Determine Estimated Cash Outlays			1
Jointly Owned Utility Plant, Maximum Period for which Escalation Rates are Considered to Determine Estimated Cash Outlays			5
PSNC Energy
Environmental
Number of MGP sites that require environmental clean-up			5
Regulatory assets			3,100,000
SCE&G
Nuclear Insurance
Maximum yearly assessment per reactor			$ 11,700,000

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012		Mar. 31, 2011
Net Income (Loss) Attributable to Parent [Abstract]
Income Available to Common Shareholders	$ 121		$ 128
Other Comprehensive Income (Loss)
Unrealized gains (losses) on cash flow hedging activities arising during period	(4)		2
Losses on cash flow hedging activities reclassified to net income	10		5
Other Comprehensive Income	6		7
Total Comprehensive Income (Loss)	127	[1]	135	[1]
SCE&G
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	72		70
Other Comprehensive Income, net of tax:
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax of $- and $-	0		0
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	72		70
Less comprehensive income attributable to noncontrolling interest	(3)		(2)
Other Comprehensive Income (Loss)
Total Comprehensive Income (Loss)	$ 69		$ 68

[1] (1) Accumulated other comprehensive loss totaled $88.1 million as of March 31, 2012 and $93.8 million as of December 31, 2011.

XML

COMMON EQUITY (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012		Mar. 31, 2011		Dec. 31, 2011	Dec. 31, 2010	May 31, 2010
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	$ 127	[1]	$ 135	[1]
Stockholders' Equity Note [Abstract]
Common Shareholders' Equity	3,977				3,889
Common Stock, Shares, Outstanding	130.4				127.4
Forward Contract Indexed to Issuer's Equity, Indexed Shares							6.6
Dividends declared	(65)		(62)
Losses recognized on cash flow hedges, net of tax	(10)		(5)
Common Stock, Shares Authorized	200				200
Common stock issued	26		25
Common Stockholders' Equity			$ 3,800			$ 3,702

[1] (1) Accumulated other comprehensive loss totaled $88.1 million as of March 31, 2012 and $93.8 million as of December 31, 2011.

XML

INCOME TAXES Income Taxes (Policies)

3 Months Ended

Mar. 31, 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

XML

LONG-TERM AND SHORT-TERM DEBT (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Debt Instrument [Line Items]
Long-term Debt, Current Maturities	$ 30	$ 31
Long- Term Debt Noncurrent including Derivative Liabilities	$ 4,862	$ 4,622

XML

RATE AND OTHER REGULATORY MATTERS (Tables)

3 Months Ended

Mar. 31, 2012

Regulated Operations [Abstract]

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

Schedule of Regulatory Assets [Table Text Block]

Millions of dollars	March 31, 2012		December 31, 2011
Regulatory Assets:
Accumulated deferred income taxes	$	243	$	243
Under-collections - electric fuel adjustment clause	6		28
Environmental remediation costs	30		30
AROs and related funding	319		316
Franchise agreements	39		40
Deferred employee benefit plan costs	390		392
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	134		154
Deferred pollution control costs	29		25
Other	47		45
Total Regulatory Assets	$	1,237	$	1,279

Schedule of Regulatory Liabilities [Table Text Block]

Regulatory Liabilities:
Accumulated deferred income taxes	$	22	$	23
Asset removal costs	671		662
Storm damage reserve	31		32
Monetization of bankruptcy claim	34		34
Deferred gains on interest rate derivatives	37		24
Other	2		3
Total Regulatory Liabilities	$	797	$	778

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	$ (2)	$ 1
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Tax	6	3
Accumulated Other Comprehensive Income (Loss), Net of Tax	88.1	93.8
SCE&G
Accumulated Other Comprehensive Income (Loss), Net of Tax	3.2	3.3
Other Comprehensive Income (Loss), Reclassification, Pension and Other Postretirement Benefit Plans, Net Gain (Loss) Recognized in Net Periodic Benefit Cost, Tax	$ 0	$ 0

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Utility Plant, Net	$ 10,255	$ 10,047
Total Current Assets	1,359	1,491
Total Deferred Debits and Other Assets	1,481	1,520
Goodwill, Writedown	230	230
Nonutility property, accumulated depreciation	135	131
Receivables, net of allowance for uncollectible accounts	6	6
SCE&G
Utility Plant, Net	8,788	8,588
Total Current Assets	940	915
Total Deferred Debits and Other Assets	1,344	1,396
Receivables, net of allowance for uncollectible accounts	3	3
VIEs | SCE&G
Utility Plant, Net	647	662
Total Current Assets	227	193
Total Deferred Debits and Other Assets	$ 60	$ 61

XML

EMPLOYEE BENEFIT PLANS

3 Months Ended

Mar. 31, 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 March 31,
Service cost	$	4.8		$	4.6		$	1.3	$	1.1
Interest cost	10.7			11.1			3.0		3.0
Expected return on assets	(14.8		)	(16.2		)	—		—
Prior service cost amortization	1.7			1.8			0.2		0.3
Transition obligation amortization	—			—			0.2		0.2
Amortization of actuarial loss	4.7			3.0			0.2		0.1
Net periodic benefit cost	$	7.1		$	4.3		$	4.9	$	4.7

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 or income related to retail electric and gas operations as a regulatory asset or liability, as applicable.  Costs totaling $3.7 million and $2.3 million were deferred for the three months ended March 31, 2012 and 2011, respectively.

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 March 31,
Service cost	$	3.9		$	3.7		$	1.0	$	0.9
Interest cost	9.1			9.4			2.4		2.4
Expected return on assets	(12.6		)	(13.8		)	—		—
Prior service cost amortization	1.4			1.5			0.2		0.2
Amortization of actuarial loss	4.0			2.6			0.1		—
Net periodic benefit cost	$	5.8		$	3.4		$	3.7	$	3.5

No contribution to the pension trust will be necessary in or for 2012, nor will limitations on benefit payments apply.   As authorized by the SCPSC, SCE&G defers all pension expense or income related to retail electric and gas operations as a regulatory asset or liability, as applicable. Costs totaling $3.7 million and $2.3 million were deferred for the three months ended March 31, 2012 and 2011, respectively.

XML

Document and Entity Information	3 Months Ended
	Mar. 31, 2012	Apr. 30, 2012
Document Information [Line Items]
Entity Registrant Name	SCANA CORP
Entity Central Index Key	0000754737
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Mar. 31, 2012
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding		130,792,209
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	Mar. 31, 2012
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding		40,296,147

XML

COMMITMENTS AND CONTINGENCIES

3 Months Ended

Mar. 31, 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.

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 2014 and will cost an additional $8.1 million, which is accrued in Other within Deferred Credits and Other Liabilities on the consolidated balance sheet.  SCE&G expects to recover any cost arising from the remediation of MGP sites through rates and insurance settlements.  At March 31, 2012, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $24.5 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 March 31, 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 two1,117-MW nuclear generation units to be constructed at the site of Summer Station, with SCE&G responsible for 55 percent of the cost and receiving 55 percent of the output, and Santee Cooper responsible for and receiving the remaining 45 percent.  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 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, including those 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.  These issues resulted in assertions of contractual entitlement to recover additional costs to be incurred. On March 29, 2012, SCE&G and the Consortium signed a preliminary agreement which set SCE&G's portion of these costs 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 included in future rate filings and will be recoverable through rates.

On February 29, 2012, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost and construction schedule that incorporates 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. That petition also includes increased capital costs of approximately $12 million (SCE&G's portion in 2007 dollars) related to transmission infrastructure. Finally, that petition includes amounts of approximately $137 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. It is anticipated that this petition will be recalled and replaced with a new petition which will also include the $138 million of additional costs referred to above.

Schedule changes identified in connection with COL delays, as well as the additional costs described above, are likely to result in changes to the amounts and timing of capital expenditures to be reflected in future quarterly reports to the SCPSC under the BLRA and in annual rate filings.  The results of an evaluation of the impact of certain of these changes are expected to be identified in the quarterly report to be filed on May 15, 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.

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 2014 and will cost an additional $8.1 million, which is accrued in Other within Deferred Credits and Other Liabilities on the consolidated balance sheet.  SCE&G expects to recover any cost arising from the remediation of MGP sites through rates and insurance settlements.  At March 31, 2012, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $24.5 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 0.55 percent of the cost and receiving 0.55 percent of the output, and Santee Cooper responsible for and receiving the remaining 0.45 percent.  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 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, including those 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.  These issues resulted in assertions of contractual entitlement to recover additional costs to be incurred. On March 29, 2012, SCE&G and the Consortium signed a preliminary agreement which set SCE&G's portion of these costs 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 included in future rate filings and will be recoverable.

On February 29, 2012, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost and construction schedule that incorporates 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. That petition also includes increased capital costs of approximately $12 million (SCE&G's portion in 2007 dollars) related to transmission infrastructure. Finally, that petition includes amounts of approximately $137 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. It is anticipated that this petition will be recalled and replaced with a new petition which will also include the $138 million of additional costs referred to above.

Schedule changes identified in connection with COL delays, as well as the additional costs described above, are likely to result in changes to the amounts and timing of capital expenditures to be reflected in future quarterly reports to the SCPSC under the BLRA and in annual rate filings.  The results of an evaluation of the impact of certain of these changes are expected to be identified in the quarterly report to be filed on May 15, 2012.

When the NRC issued the COLs for the New Units, it imposed two conditions on the COLs, with the first requiring inspection and testing of certain components of the New Units' passive cooling system, and the second requiring the development of strategies to respond to extreme natural events resulting in the loss of power at the New Units.  In addition, the NRC directed the Office of New Reactors to issue to SCE&G an order requiring enhanced, reliable spent fuel pool instrumentation, as well as a request for information related to emergency plant staffing.  These conditions and requirements are responsive to the NRC's Near-Term Task Force report titled “Recommendations for Enhancing Reactor Safety in the 21st Century.”  This report was prepared in the wake of the March 2011 tsunami resulting from a massive earthquake, which severely damaged several nuclear generating units and their back-up cooling systems, in Japan.  SCE&G is evaluating the impact these conditions and requirements impose on the construction and operation of the New Units.  SCE&G cannot predict what additional regulatory or other outcomes may be implemented in the United States, or how such initiatives would impact SCE&G's existing Summer Station or the construction or operation of the New Units.

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

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CONSOLIDATED STATEMENTS OF INCOME (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Operating Revenues:
Electric Domestic Regulated Revenue	$ 545	$ 558
Gas-regulated	277	362
Gas-nonregulated	285	361
Regulated and Unregulated Operating Revenue	1,107	1,281
Operating Expenses [Abstract]
Fuel used in electric generation	181	211
Purchased power	6	2
Gas purchased for resale	366	512
Other operation and maintenance	175	170
Depreciation and amortization	89	86
Other taxes	52	52
Total Operating Expenses	869	1,033
Operating Income	238	248
Other Income (Expense):
Other income	14	13
Other expenses	(10)	(9)
Interest charges, net of allowance for borrowed funds used during construction of $2, $2	(72)	(70)
Allowance for equity funds used during construction	3	3
Total Other Expense	(65)	(63)
Income Before Income Tax Expense	173	185
Income Tax Expense	52	57
Income Available to Common Shareholders	121	128
Per Common Share Data
Basic Earnings Per Share of Common Stock (in dollars per share)	$ 0.93	$ 1.00
Diluted Earnings Per Share of Common Stock (in dollars per share)	$ 0.91	$ 1.00
Weighted Average Common Shares Outstanding (millions)
Weighted Average Number of Shares Outstanding, Basic	130.3	127.9
Weighted Average Number of Shares Outstanding, Diluted	132.2	129.0
Dividends Declared Per Share of Common Stock (in dollars per share)	$ 0.495	$ 0.485
SCE&G
Operating Revenues:
Electric Domestic Regulated Revenue	547	560
Gas-regulated	116	144
Total Operating Revenues	663	704
Operating Expenses [Abstract]
Fuel used in electric generation	183	213
Purchased power	6	2
Gas purchased for resale	59	88
Other operation and maintenance	138	132
Depreciation and amortization	73	71
Other taxes	48	47
Total Operating Expenses	507	553
Operating Income	156	151
Other Income (Expense):
Other income	0	1
Other expenses	(4)	(4)
Interest charges, net of allowance for borrowed funds used during construction of $2, $2	(51)	(50)
Allowance for equity funds used during construction	3	3
Total Other Expense	(52)	(50)
Income Before Income Tax Expense	104	101
Income Tax Expense	32	31
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	72	70
Net Income (Loss) Attributable to Noncontrolling Interest	3	2
Net Income (Loss) Attributable to Parent	69	68
Weighted Average Common Shares Outstanding (millions)
Dividends, Common Stock, Cash	$ 53	$ 51

XML

COMMON EQUITY

3 Months Ended

Mar. 31, 2012

Stockholders' Equity Note [Abstract]

COMMON EQUITY

COMMON EQUITY

Changes in common equity during the three months ended March 31, 2012 and 2011 were as follows:

Millions of dollars	2012			2011
Balance at January 1,	$	3,889		$	3,702
Common stock issued	26			25
Dividends declared	(65		)	(62		)
Comprehensive income	127			135
Balance as of March 31,	$	3,977		$	3,800

Authorized shares of common stock were 200 million as of March 31, 2012 and December 31, 2011.  Outstanding shares of common stock were 130.4 million and 127.4 million at March 31, 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 no later than December 31, 2012.  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 three months ended March 31, 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	24			—			24
Dividends declared	(51		)	(2		)	(53		)
Comprehensive income	69			3			72
Balance as of March 31, 2012	$	3,707		$	109		$	3,816
Balance at January 1, 2011	$	3,437		$	104		$	3,541
Capital contribution from parent	24			—			24
Dividends declared	(49		)	(2		)	(51		)
Comprehensive income	68			2			70
Balance as of March 31, 2011	$	3,480		$	104		$	3,584

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

3 Months Ended

Mar. 31, 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. On March 15, 2012, SCE&G, 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. By order dated April 24, 2012, the SCPSC approved the settlement agreement.

On July 15, 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 its annual update on DSM Programs and rate rider. By order dated May 24, 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 its annual update on DSM Programs and rate rider. By order dated April 25, 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 becomes 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.

    On November 15, 2010, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost schedule that, among other things, incorporated then-identifiable capital costs of $173.9 million (SCE&G's portion in 2007 dollars), and by order dated May 16, 2011, the SCPSC approved the updated capital costs schedule as outlined in the petition.

 On February 29, 2012, SCE&G filed a petition with the SCPSC seeking an order approving a further updated capital cost and construction schedule that incorporates additional identifiable capital costs of approximately of $6 million (SCE&G's portion in 2007 dollars) related to new federal healthcare laws, information security measures, and certain minor design modifications. That petition also includes increased capital costs of approximately $12 million (SCE&G's portion in 2007 dollars) related to transmission infrastructure. Finally, that petition includes amounts of approximately $137 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. That petition is expected to be recalled and replaced with a new petition which will include the costs arising from the resolution of the commercial claims discussed in Note 9 to the consolidated financial statements (e.g., those 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).

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

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

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.

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 adjusted periodically 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-collections of the delivered cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy’s gas purchasing practices annually. In addition, PSNC Energy utilizes a CUT which allows it to adjust its base rates semi-annually for residential and commercial customers based on average per customer consumption.

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

In 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. On February 2, 2012, the Public Staff of the NCUC filed a motion requesting the NCUC reconsider and modify its order by reassigning certain charges (totaling approximately $0.4 million) from the cost of gas. On April 4, 2012 the NCUC issued an order denying the Public Staff's motion for reconsideration.

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	March 31, 2012		December 31, 2011
Regulatory Assets:
Accumulated deferred income taxes	$	243	$	243
Under-collections - electric fuel adjustment clause	6		28
Environmental remediation costs	30		30
AROs and related funding	319		316
Franchise agreements	39		40
Deferred employee benefit plan costs	390		392
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	134		154
Deferred pollution control costs	29		25
Other	47		45
Total Regulatory Assets	$	1,237	$	1,279

Regulatory Liabilities:
Accumulated deferred income taxes	$	22	$	23
Asset removal costs	671		662
Storm damage reserve	31		32
Monetization of bankruptcy claim	34		34
Deferred gains on interest rate derivatives	37		24
Other	2		3
Total Regulatory Liabilities	$	797	$	778

Accumulated deferred income tax liabilities arising 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 by April 2013.  SCE&G is allowed to accrue interest on the base fuel deferred balances through the recovery period.

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 23 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 this purpose.  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 $9.3 million at March 31, 2012 and are being recovered through utility rates over approximately 30 years.  The remaining costs relate to Wateree Station, for which the Company will seek recovery in future proceedings 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 three months ended March 31, 2012 and 2011, SCE&G applied costs of $0.8 million and $0.7 million, respectively, to the reserve.  Pursuant to the SCPSC’s July 2010 retail electric rate order approving an electric rate increase, SCE&G suspended collection of storm damage reserve funds indefinitely.

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

The SCPSC, the NCUC or the FERC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other regulatory assets include, but are not limited to, certain costs which have not been approved for recovery by the SCPSC or by FERC. In recording 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. On March 15, 2012, SCE&G, 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. By order dated April 24, 2012, the SCPSC approved the settlement agreement.

On July 15, 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 its annual update on DSM Programs and rate rider. By order dated May 24, 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 its annual update on DSM Programs and rate rider. By order dated April 25, 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 becomes 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.

    On November 15, 2010, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost schedule that, among other things, incorporated then-identifiable capital costs of $173.9 million (SCE&G's portion in 2007 dollars), and by order dated May 16, 2011, the SCPSC approved the updated capital costs schedule as outlined in the petition.

 On February 29, 2012, SCE&G filed a petition with the SCPSC seeking an order approving a further updated capital cost and construction schedule that incorporates additional identifiable capital costs of approximately of $6 million (SCE&G's portion in 2007 dollars) related to new federal healthcare laws, information security measures, and certain minor design modifications. That petition also includes increased capital costs of approximately $12 million (SCE&G's portion in 2007 dollars) related to transmission infrastructure. Finally, that petition includes amounts of approximately $137 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. That petition is expected to be recalled and replaced with a new petition which will include the costs arising from the resolution of the commercial claims discussed in Note 9 to the consolidated financial statements (e.g., those 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).

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

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

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.

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	March 31, 2012		December 31, 2011
Regulatory Assets:
Accumulated deferred income taxes	$	238	$	238
Under collections – electric fuel adjustment clause	6		28
Environmental remediation costs	25		25
AROs and related funding	303		301
Franchise agreements	39		40
Deferred employee benefit plan costs	346		348
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	134		154
Deferred pollution control costs	29		25
Other	44		41
Total Regulatory Assets	$	1,164	$	1,206
Regulatory Liabilities:
Accumulated deferred income taxes	$	22	$	23
Asset removal costs	499		493
Storm damage reserve	31		32
Deferred gains on interest rate derivatives	37		24
Other	1		3
Total Regulatory Liabilities	$	590	$	575

Accumulated deferred income tax liabilities arising 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 by April 2013.  SCE&G is allowed to accrue interest on the base fuel deferred balances through the recovery period.

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 23 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 this purpose.  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 $9.3 million at March 31, 2012 and are being recovered through utility rates over approximately 30 years.  The remaining costs relate to Wateree Station, for which SCE&G will seek recovery in future proceedings 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 three months ended March 31, 2012 and 2011, SCE&G applied costs of $0.8 million and $0.7 million, respectively, to the reserve.  Pursuant to the SCPSC’s July 2010 retail electric rate order approving an electric rate increase, SCE&G suspended collection of the storm damage reserve indefinitely.

The SCPSC or the FERC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other regulatory assets include, but are not limited to, certain costs which have not been approved for recovery by the SCPSC or by FERC. In recording 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)

3 Months Ended

Mar. 31, 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:

In Millions	2012	2011
Weighted Average Shares Outstanding - Basic	130.3	127.9
Net effect of dilutive equity forward shares	1.9	1.1
Weighted Average Shares - Diluted	132.2	129.0

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SEGMENT OF BUSINESS INFORMATION

3 Months Ended

Mar. 31, 2012

Segment Reporting Information [Line Items]

SEGMENT OF BUSINESS INFORMATION

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		Segment
Millions of dollars	Revenue			Revenue			Income		Income		Assets
Three Months Ended March 31, 2012
Electric Operations	$	545		$	2		$	127	n/a		$	8,449
Gas Distribution	274			—			83		n/a		2,277
Retail Gas Marketing	153			—			n/a		$	11	157
Energy Marketing	132			26			n/a		2		95
All Other	11			106			7		5		1,337
Adjustments/Eliminations	(8		)	(134		)	21		103		1,265
Consolidated Total	$	1,107		$	—		$	238	$	121	$	13,580
Three Months Ended March 31, 2011
Electric Operations	$	558		$	2		$	122	n/a		$	8,002
Gas Distribution	360			—			84		n/a		2,177
Retail Gas Marketing	202			—			n/a		$	22	201
Energy Marketing	158			45			n/a		1		95
All Other	10			102			5		1		1,262
Adjustments/Eliminations	(7		)	(149		)	37		104		1,136
Consolidated Total	$	1,281		$	—		$	248	$	128	$	12,873

SCE&G

Segment Reporting Information [Line Items]

SEGMENT OF BUSINESS INFORMATION

SEGMENT OF BUSINESS INFORMATION

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

	External		Operating Income			Earnings Available to Common		Segment
Millions of Dollars	Revenue		(Loss)			Shareholder		Assets
Three Months Ended March 31, 2012
Electric Operations	$	547	$	127		n/a		$	8,449
Gas Distribution	116		29			n/a		627
Adjustments/Eliminations	—		—			$	69	2,140
Consolidated Total	$	663	$	156		$	69	$	11,216
Three Months Ended March 31, 2011
Electric Operations	$	560	$	122		n/a		$	8,002
Gas Distribution	144		30			n/a		587
Adjustments/Eliminations	—		(1		)	$	68	1,946
Consolidated Total	$	704	$	151		$	68	$	10,535

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DERIVATIVE FINANCIAL INSTRUMENTS

3 Months Ended

Mar. 31, 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.

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 March 31, 2012
Cash flow	—	4,141,000	27,592,275	31,733,275
Not designated (a)	10,100,000	—	30,427,609	40,527,609
Total (a)	10,100,000	4,141,000	58,019,884	72,260,884
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 8,694,000 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 party to interest rate swaps designated as fair value hedges with aggregate notional amounts of $3.2 million and $253.2 million at March 31, 2012 and December 31, 2011, respectively, and was party to interest rate swaps designated as cash flow hedges with aggregate notional amounts of $322.6 million and $822.6 million, respectively.

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 March 31, 2012
Derivatives designated as hedging instruments
Interest rate contracts	Prepayments and other	—		Other current liabilities	$	5
				Other deferred credits and other liabilities	80
Commodity contracts	Prepayments and other	$	1	Prepayments and other	2
	Other current liabilities	1		Other current liabilities	7
				Other deferred credits and other liabilities	2
Total		$	2		$	96
Derivatives not designated as hedging instruments
Energy management contracts	Prepayments and other	$	19	Prepayments and other	$	3
	Other deferred debits and other assets	12		Other current liabilities	16
				Other deferred credits and other liabilities	11
Total		$	31		$	30

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 (reductions) to interest expenses of $0.2 million and $(2.5) million for the three months ended March 31, 2012 and 2011, respectively.

Derivatives in Cash Flow Hedging Relationships

	Gain (Loss) Deferred		Gain (Loss) Reclassified from
Derivatives in Cash Flow	in Regulatory Accounts		Deferred Accounts into Income
Hedging Relationships	(Effective Portion)		(Effective Portion)
Millions of dollars			Location	Amount
Three Months Ended March 31, 2012
Interest rate contracts	$	30	Interest expense	$	(1	)
Three Months Ended March 31, 2011
Interest rate contracts	$	6	Interest expense	$	(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
Three Months Ended March 31, 2012
Interest rate contracts	$	—		Interest expense	$	(2	)
Commodity contracts	(4		)	Gas purchased for resale	(8		)
Total	$	(4	)		$	(10	)
Three Months Ended March 31, 2011
Interest rate contracts	$	3		Interest expense	$	(1	)
Commodity contracts	(1		)	Gas purchased for resale	(4		)
Total	$	2			$	(5	)

As of March 31, 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 $4.9 million as an increase to gas cost and approximately $5.8 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels.  As of March 31, 2012, all of the Company’s commodity cash flow hedges settle by their terms before the end of 2014.

Derivatives not designated as Hedging Instruments	Gain (Loss) Recognized in Income
Millions of dollars	Location	2012			2011
First Quarter
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 months ended March 31, 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 March 31, 2012 and December 31, 2011, the Company has posted $94.0 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 March 31, 2012 and December 31, 2011, the Company would be required to post an additional $25.5 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 March 31, 2012 and December 31, 2011 is $119.5 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

SCE&G 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.  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 consolidated statements of cash flows.

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 1,010,000 DT at March 31, 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 $221.4 million at March 31, 2012 and $471.4 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 (a)	Value		Location (a)	Value
As of March 31, 2012
Derivatives designated as hedging instruments
Interest rate contracts				Other current liabilities	$	2
				Other deferred credits and other liabilities	55
Total					$	57
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

(a) Asset derivatives represent unrealized gains to Consolidated SCE&G, and liability derivatives represent unrealized losses. In Consolidated SCE&G’s condensed consolidated balance sheet, 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 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
Three Months Ended March 31, 2012
Interest rate contracts	$	30	Interest expense	$	(1	)
Three Months Ended March 31, 2011
Interest rate contracts	$	6	Interest expense	$	(1	)

	Gain (Loss) Recognized in Income
Derivatives Not Designated as
Hedging Instruments
Millions of dollars	Location	Amount
Three Months Ended March 31, 2012
Commodity contracts	Gas purchased for resale	$	(1	)
Three Months Ended March 31, 2011
Commodity contracts	Gas purchased for resale	$	(1	)

Hedge Ineffectiveness

Other gains (losses) recognized in income representing interest rate hedge ineffectiveness were insignificant for the three months ended March 31, 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 March 31, 2012 and December 31, 2011, Consolidated SCE&G has posted $39.1 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 March 31, 2012 and December 31, 2011, Consolidated SCE&G would be required to post an additional $17.8 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 March 31, 2012 and December 31, 2011 is $56.9 million and $76.7 million, respectively.

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LONG-TERM AND SHORT-TERM DEBT

3 Months Ended

Mar. 31, 2012

Debt Instrument [Line Items]

Long-term Debt [Text Block]

LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

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.

In January 2012, SCE&G issued $250 million of 4.35% first mortgage bonds due February 1, 2042. Proceeds from the sale 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 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	March 31, 2012			December 31, 2011			March 31, 2012			December 31, 2011			March 31, 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)	$	117		$	131		$	468		$	512		—			$	10
Weighted average interest rate	0.85		%	0.63		%	0.50		%	0.56		%	—		%	0.57		%
Letters of credit supported by LOC	$	3		$	3		$	0.3		$	0.3		—			—
Available	$	180		$	166		$	632		$	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.

SCE&G

Debt Instrument [Line Items]

Long-term Debt [Text Block]

LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

     In January 2012, SCE&G issued $250 million of 4.35% first mortgage bonds due February 1, 2042. Proceeds from the sale 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	March 31, 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)	$	468		$	512
Weighted average interest rate	0.50		%	0.56		%
Letters of credit supported by LOC	$	0.3		$	0.3
Available	$	632		$	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.

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INCOME TAXES

3 Months Ended

Mar. 31, 2012

income tax [Line Items]

Income Tax Disclosure [Text Block]

INCOME TAXES

In connection with the change in method of accounting for certain repair costs in prior years, 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 March 31, 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 the change in method of accounting for certain repair costs in prior years, 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 March 31, 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

3 Months Ended

Mar. 31, 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 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)
Assets -	Available for sale securities	$	8	—
	Energy management contracts	—		$	31
	Commodity contracts	1		1
Liabilities -	Interest rate contracts	—		85
	Commodity contracts	2		9
	Energy management contracts	3		29
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 March 31, 2012 and December 31, 2011 were as follows:

	March 31, 2012				December 31, 2011
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	4,891.9	$	5,669.6	$	4,653.0	$	5,479.2

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

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

SCE&G values commodity derivative assets and liabilities using unadjusted NYMEX prices to determine fair value, and considers such measure of fair value to be Level 1 for exchange traded instruments and Level 2 for over-the-counter instruments.  Consolidated SCE&G’s interest rate swap agreements are valued using discounted cashflow models with independently sourced market data.  Fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows: 

		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets	Significant Other Observable Inputs
Millions of dollars		(Level 1)	(Level 2)
Assets -	Interest rate contracts	—	—
Liabilities-	Interest rate contracts	—	$57
As of December 31, 2011
Assets -	Interest rate contracts	—	$1
Liabilities -	Interest rate contracts	—	77

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 March 31, 2012 and December 31, 2011 were as follows:

	March 31, 2012				December 31, 2011
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	3,482.6	$	4,126.3	$	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
	Mar. 31, 2012	Jul. 31, 2012	Dec. 31, 2011	Mar. 31, 2011
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	9,300,000
Regulatory liabilities	797,000,000		778,000,000	778,000,000
Amount allowed to be recovered through electric rates to offset incremental storm damage costs	0
Annual amount of storm damage costs which can not be offset by amounts recovered through electric rates	2.5
Accrual period of nuclear refueling charges (in months)	18
Accumulated deferred income taxes
Regulatory Liabilities:
Regulatory liabilities	22,000,000		23,000,000
Asset Retirement Obligation Costs [Member]
Regulatory Liabilities:
Regulatory liabilities	671,000,000		662,000,000
Storm damage reserve
Regulatory Liabilities:
Regulatory liabilities	31,000,000		32,000,000
Monetization of bankruptcy claim
Regulatory Liabilities:
Regulatory liabilities	34,000,000		34,000,000
Deferred gains on interest rate derivatives
Regulatory Liabilities:
Regulatory liabilities	37,000,000		24,000,000
Other.
Regulatory Liabilities:
Regulatory liabilities	2,000,000		3,000,000
SCE&G
Regulatory Liabilities:
Regulatory liabilities	$ 590,000,000		$ 575,000,000

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

3 Months Ended

Mar. 31, 2012

Accounting Policies [Abstract]

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 27%  and 45% of PSNC Energy’s natural gas inventory at March 31, 2012 and December 31,2011, respectively, with a carrying value of $10.9 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.

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

3 Months Ended

Mar. 31, 2012

Long-Term Debt and Liquidity [Abstract]

Schedule of Line of Credit Facilities [Table Text Block]

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

	SCANA						SCE&G						PSNC Energy
Millions of dollars	March 31, 2012			December 31, 2011			March 31, 2012			December 31, 2011			March 31, 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)	$	117		$	131		$	468		$	512		—			$	10
Weighted average interest rate	0.85		%	0.63		%	0.50		%	0.56		%	—		%	0.57		%
Letters of credit supported by LOC	$	3		$	3		$	0.3		$	0.3		—			—
Available	$	180		$	166		$	632		$	588		$	100		$	90

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DERIVATIVE FINANCIAL INSTRUMENTS (Details 3) (USD $)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 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	$ 0	$ (2,500,000)
Effect of Cash Flow Hedges on Statement of Income
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	(10,000,000)	(5,000,000)
Gain or (Loss) Deferred in Regulatory Accounts (Effective Portion), classified in interest expense	(4,000,000)	0
Derivative, Credit Risk Related Contingent Features [Abstract]
Collateral Already Posted, Aggregate Fair Value	94,000,000		140,300,000
Additional collateral required to be posted to counterparties if all underlying contingent features were fully triggered	25,500,000		50,700,000
Aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position	119,500,000		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	8,000,000	4,000,000
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred	4,900,000
Gain or (Loss) Deferred in Regulatory Accounts (Effective Portion), classified in interest expense	4,000,000	0
Derivatives not designated as hedging instruments - gain (loss) recognized in income, classified in gas purchased for resale	(1,000,000)	(1)
Interest Rate Contract
Gain (Loss) on Derivatives
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net	30,000,000	0
Effect of Cash Flow Hedges on Statement of Income
Gain or (Loss) Deferred in Regulatory Accounts (Effective Portion), classified in interest expense	(1,000,000)	(1,000,000)
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	2,000,000	1,000,000
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred	5,800,000
Gain or (Loss) Deferred in Regulatory Accounts (Effective Portion), classified in interest expense	$ 0	$ 0

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CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Interest charges, allowance for borrowed funds used during construction	$ 2	$ 2
SCE&G
Interest charges, allowance for borrowed funds used during construction	$ 2	$ 2

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

3 Months Ended

Mar. 31, 2012

Significant Accounting Policies [Line Items]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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:

In Millions	2012	2011
Weighted Average Shares Outstanding - Basic	130.3	127.9
Net effect of dilutive equity forward shares	1.9	1.1
Weighted Average Shares - Diluted	132.2	129.0

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 27%  and 45% of PSNC Energy’s natural gas inventory at March 31, 2012 and December 31,2011, respectively, with a carrying value of $10.9 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 [Line Items]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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 $489 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, fossil fuel 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 Matter

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)

3 Months Ended

Mar. 31, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Natural gas derivative contracts outstanding

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 March 31, 2012
Cash flow	—	4,141,000	27,592,275	31,733,275
Not designated (a)	10,100,000	—	30,427,609	40,527,609
Total (a)	10,100,000	4,141,000	58,019,884	72,260,884
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 8,694,000 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.

Fair value of energy-related derivatives and interest rate derivatives balance sheet location

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 March 31, 2012
Derivatives designated as hedging instruments
Interest rate contracts	Prepayments and other	—		Other current liabilities	$	5
				Other deferred credits and other liabilities	80
Commodity contracts	Prepayments and other	$	1	Prepayments and other	2
	Other current liabilities	1		Other current liabilities	7
				Other deferred credits and other liabilities	2
Total		$	2		$	96
Derivatives not designated as hedging instruments
Energy management contracts	Prepayments and other	$	19	Prepayments and other	$	3
	Other deferred debits and other assets	12		Other current liabilities	16
				Other deferred credits and other liabilities	11
Total		$	31		$	30

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.

Derivatives in Cash Flow Hedging Relationships

Derivatives in Cash Flow Hedging Relationships

	Gain (Loss) Deferred		Gain (Loss) Reclassified from
Derivatives in Cash Flow	in Regulatory Accounts		Deferred Accounts into Income
Hedging Relationships	(Effective Portion)		(Effective Portion)
Millions of dollars			Location	Amount
Three Months Ended March 31, 2012
Interest rate contracts	$	30	Interest expense	$	(1	)
Three Months Ended March 31, 2011
Interest rate contracts	$	6	Interest expense	$	(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
Three Months Ended March 31, 2012
Interest rate contracts	$	—		Interest expense	$	(2	)
Commodity contracts	(4		)	Gas purchased for resale	(8		)
Total	$	(4	)		$	(10	)
Three Months Ended March 31, 2011
Interest rate contracts	$	3		Interest expense	$	(1	)
Commodity contracts	(1		)	Gas purchased for resale	(4		)
Total	$	2			$	(5	)

Derivatives not designated as Hedging Instruments Gain (Loss) Recognized in Income

Derivatives not designated as Hedging Instruments	Gain (Loss) Recognized in Income
Millions of dollars	Location	2012			2011
First Quarter
Commodity contracts	Gas purchased for resale	$	(1	)	$	(1	)

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INCOME TAXES (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012
Changes to Unrecognized Tax Benefits
Balance at the beginning 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

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AFFILIATED TRANSACTIONS - SCEG

3 Months Ended

Mar. 31, 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 $10.0 million and $7.9 million for the three months ended March 31, 2012 and 2011, respectively.  SCE&G had approximately $3.1 million and $2.5 million payable to CGT for transportation services at March 31, 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 $25.4 million and $45.4 million for the three months ended March 31, 2012 and 2011, respectively.  SCE&G’s payables to SEMI for such purposes were $3.5 million and $13.2 million as of March 31, 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 $8.7 million at March 31, 2012 and $8.5 million at December 31, 2011.  SCE&G’s payables to these affiliates were $8.8 million at March 31, 2012 and $8.6 million at December 31, 2011.  SCE&G’s total purchases were $27.1 million and $13.0 million for the three months ended March 31, 2012 and 2011, respectively.  SCE&G’s total sales were $26.9 million and $12.9 million for the three months ended March 31, 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 three months ended March 31, 2012 or 2011.  At March 31, 2012 and December 31, 2011, Consolidated SCE&G owed an affiliate $78.6 million and $58.5 million, respectively.