Dominion Energy South Carolina 10Q 2011 Q1 Quarterly report

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, 2011

o	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 o South Carolina Electric & Gas Company Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

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

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

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

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

SCANA Corporation Yes o No x South Carolina Electric & Gas Company Yes o 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 27, 2011
SCANA Corporation	Without Par Value	128,428,337
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, 2011

			Page

Cautionary Statement Regarding Forward-Looking Information			3

Definitions			4

PART I. FINANCIAL INFORMATION

SCANA Corporation Financial Section			5
	Item 1.	Financial Statements	6
		Condensed Consolidated Balance Sheets	6
		Condensed Consolidated Statements of Income	8
		Condensed Consolidated Statements of Cash Flows	9
		Condensed Consolidated Statements of Comprehensive Income	10
		Notes to Condensed Consolidated Financial Statements	11
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	30
	Item 4.	Controls and Procedures	31

South Carolina Electric & Gas Company Financial Section			32
	Item 1.	Financial Statements	33
		Condensed Consolidated Balance Sheets	33
		Condensed Consolidated Statements of Income	35
		Condensed Consolidated Statements of Cash Flows	36
		Condensed Consolidated Statements of Comprehensive Income	37
		Notes to Condensed Consolidated Financial Statements	38
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	49
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	54
	Item 4.	Controls and Procedures	55

PART II. OTHER INFORMATION			56

	Item 6.	Exhibits	56

Signatures			57

Exhibit Index			58

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

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

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

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

(7)		the results of short- and long-term financing efforts, including future 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 by counterparties as and when due;

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

(12)		the results of efforts to attract and retain joint venture partners for SCE&G’s new nuclear generation project;

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

(14)		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;

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

(16)		labor disputes;

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

(18)		changes in taxes;

(19)		inflation or deflation;

(20)		compliance with regulations; and

(21)		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.

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
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
CUT		Customer Usage Tracker
DHEC		South Carolina Department of Health and Environmental Control
DSM Programs		Demand reduction and energy efficiency programs
DT		Dekatherms
Energy Marketing		The divisions of SEMI, excluding SCANA Energy
EPA		United States Environmental Protection Agency
eWNA		Pilot Electric WNA
FEIS		Final Environmental Impact Statement
FERC		United States Federal Energy Regulatory Commission
Fuel Company		South Carolina Fuel Company, Inc.
GENCO		South Carolina Generating Company, Inc.
LOC		Lines of credit
MGP		Manufactured Gas Plant
MW or MWh		Megawatt or megawatt-hour
NASDAQ		The NASDAQ Stock Market, Inc.
NCUC		North Carolina Utilities Commission
New Units		Nuclear Units 2 and 3 to be constructed at Summer Station
NMST		Negotiated Market Sales Tariff
NRC		United States Nuclear Regulatory Commission
NYMEX		New York Mercantile Exchange
OATT		Open Access Transmission Tariff
OCI		Other Comprehensive Income
ORS		South Carolina Office of Regulatory Staff
OUC		Orlando Utilities Commission
PGA		Purchased Gas Adjustment
PRP		Potentially Responsible Party
PSNC Energy		Public Service Company of North Carolina, Incorporated
Retail Gas Marketing		SCANA Energy
RSA		Natural Gas Rate Stabilization Act
Santee Cooper		South Carolina Public Service Authority
SCANA		SCANA Corporation, the parent company
SCANA Energy		A division of SEMI which markets natural gas in Georgia
SCE&G		South Carolina Electric & Gas Company
SCEUC		South Carolina Energy Users
SCPSC		Public Service Commission of South Carolina
SCR		Selective Catalytic Reactor
SEC		United States Securities and Exchange Commission
SEMI		SCANA Energy Marketing, Inc.
Summer Station		V. C. Summer Nuclear Station
USACE		United States Army Corps of Engineers
VIE		Variable Interest Entity
Westinghouse		Westinghouse Electric Company LLC
WNA		Weather Normalization Adjustment

SCANA CORPORATION

FINANCIAL SECTION

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

SCANA CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31,			December 31,
Millions of dollars	2011			2010
Assets

Utility Plant In Service	$	11,783		$	11,714
Accumulated Depreciation and Amortization	(3,541		)	(3,495		)
Construction Work in Progress	1,197			1,081
Nuclear Fuel, Net of Accumulated Amortization	128			132
Goodwill, net of accumulated amortization and writedown of $276	230			230
Utility Plant, Net	9,797			9,662

Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation of $122 and $118	296			299
Assets held in trust, net-nuclear decommissioning	78			76
Other investments	84			78
Nonutility Property and Investments, Net	458			453

Current Assets:
Cash and cash equivalents	122			55
Receivables, net of allowance for uncollectible accounts of $11 and $9	645			837
Inventories (at average cost):
Fuel and gas supply	288			316
Materials and supplies	126			125
Emission allowances	5			6
Prepayments and other	188			271
Deferred income taxes	21			21
Total Current Assets	1,395			1,631

Deferred Debits and Other Assets:
Regulatory assets	1,066			1,061
Other	157			161
Total Deferred Debits and Other Assets	1,223			1,222
Total	$	12,873		$	12,968

	March 31,		December 31,
Millions of dollars	2011		2010
Capitalization and Liabilities

Common Equity	$	3,800	$	3,702
Long-Term Debt, net	3,989		4,152
Total Capitalization	7,789		7,854

Current Liabilities:
Short-term borrowings	512		420
Current portion of long-term debt	587		337
Accounts payable	294		526
Customer deposits and customer prepayments	100		100
Taxes accrued	47		146
Interest accrued	72		72
Dividends declared	62		61
Derivative financial instruments	36		65
Other	115		140
Total Current Liabilities	1,825		1,867

Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,406		1,391
Deferred investment tax credits	50		56
Asset retirement obligations	503		497
Pension and other postretirement benefits	204		202
Regulatory liabilities	923		913
Other	173		188
Total Deferred Credits and Other Liabilities	3,259		3,247

Commitments and Contingencies (Note 9)	-		-
Total	$	12,873	$	12,968

See Notes to Condensed Consolidated Financial Statements.

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended March 31,
Millions of dollars, except per share amounts	2011			2010
Operating Revenues:
Electric	$	558		$	540
Gas - regulated	362			430
Gas - nonregulated	361			458
Total Operating Revenues	1,281			1,428

Operating Expenses:
Fuel used in electric generation	211			235
Purchased power	2			2
Gas purchased for resale	512			658
Other operation and maintenance	170			172
Depreciation and amortization	86			83
Other taxes	52			48
Total Operating Expenses	1,033			1,198

Operating Income	248			230

Other Income (Expense):
Other income	13			14
Other expenses	(9		)	(10		)
Interest charges, net of allowance for borrowed funds used during construction of $2 and $2	(70		)	(65		)
Allowance for equity funds used during construction	3			3
Total Other Expense	(63		)	(58		)

Income Before Income Tax Expense	185			172
Income Tax Expense	57			45
Income Available to Common Shareholders of SCANA	$	128		$	127

Per Common Share Data
Basic Earnings Per Share of Common Stock	$	1.00		$	1.02
Diluted Earnings Per Share of Common Stock	$	1.00		$	1.02
Weighted Average Common Shares Outstanding (millions)
Basic	127.9			123.8
Diluted	129.0			123.9
Dividends Declared Per Share of Common Stock	$	.485		$	.475

See Notes to Condensed Consolidated Financial Statements.

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended
	March 31,
Millions of dollars	2011			2010
Cash Flows From Operating Activities:
Net income	$	128		$	127
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	11			8
Depreciation and amortization	88			88
Amortization of nuclear fuel	9			9
Allowance for equity funds used during construction	(3		)	(3		)
Carrying cost recovery	-			(1		)
Cash provided (used) by changes in certain assets and liabilities:
Receivables	192			(3		)
Inventories	17			56
Prepayments and other	83			26
Regulatory liabilities	(2		)	1
Accounts payable	(146		)	(33		)
Taxes accrued	(99		)	(73		)
Interest accrued	-			1
Regulatory assets	14			(31		)
Changes in other assets	-			(15		)
Changes in other liabilities	(52		)	16
Net Cash Provided From Operating Activities	241			173
Cash Flows From Investing Activities:
Utility property additions and construction expenditures	(293		)	(223		)
Proceeds from investments and sale of assets	1			8
Nonutility property additions	(2		)	(7		)
Purchase of investments	(6		)	(2		)
Net Cash Used For Investing Activities	(300		)	(224		)
Cash Flows From Financing Activities:
Proceeds from issuance of common stock	25			26
Proceeds from issuance of long-term debt	379			202
Repayment of long-term debt	(309		)	(9		)
Dividends	(61		)	(58		)
Short-term borrowings, net	92			(115		)
Net Cash Provided From Financing Activities	126			46
Net Increase (Decrease) In Cash and Cash Equivalents	67			(5		)
Cash and Cash Equivalents, January 1	55			162
Cash and Cash Equivalents, March 31	$	122		$	157

Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $2 and $2)	$	67		$	63
- Income taxes	-			-

Noncash Investing and Financing Activities:
Accrued construction expenditures	93			101

See Notes to Condensed Consolidated Financial Statements.

SCANA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended
	March 31,
Millions of dollars	2011		2010
Net Income	$	128	$	127
Other Comprehensive Income (Loss), net of tax:
Unrealized holding gains (losses) arising during period, net	2		(11		)
Reclassified to net income:
Losses on cash flow hedging activities	5		5
Amortization of deferred employee benefit plan costs, net of taxes	-		1
Comprehensive income attributable to SCANA Corporation (1)	$	135	$	122

(1) Accumulated other comprehensive loss totaled $40.0 million as of March 31, 2011 and $46.6 million as of December 31, 2010.

See Notes to Condensed Consolidated Financial Statements.

SCANA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 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, 2010. 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 income available to common shareholders 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.

A reconciliation of the weighted average number of common shares for year to date March 31 for basic and dilutive purposes is as follows:

In Millions	2011	2010
Weighted Average Shares Outstanding - Basic	127.9	123.8
Net effect of dilutive stock-based compensation plans and equity forward contracts	1.1	0.1
Weighted Average Shares - Diluted	129.0	123.9

Asset Management and Supply Service Agreements

PSNC Energy utilizes asset management and supply service agreements with counterparties for certain natural gas storage facilities. At March 31, 2011, such counterparties held 40% of PSNC Energy’s natural gas inventory, with a carrying value of $8.3 million, 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.

2. RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric

SCE&G’s electric rates are established 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. Effective with the first billing cycle of May 2010, the SCPSC approved a settlement agreement authorizing SCE&G to decrease the fuel cost portion of its electric rates. The settlement agreement incorporated SCE&G’s proposal to accelerate the recognition of $17.4 million of previously deferred state income tax credits and record an offsetting reduction to the recovery of fuel costs. In addition, SCE&G agreed to defer recovery of its actual undercollected base fuel costs as of April 30, 2010 until May 2011. SCE&G is allowed to charge and recover carrying costs monthly on the actual base fuel costs undercollected balance as of the end of each month during this deferral period. In February 2011, SCE&G filed for an increase to the cost of fuel component of its rates to be effective with the first billing cycle of May 2011. The annual fuel hearing was conducted on March 24, 2011, and a

settlement agreement was reached among ORS, the SCEUC, and SCE&G which will allow SCE&G to recover the actual base fuel under-collected balance as of April 30, 2011, over a two year period and charge carrying cost on the deferred balance. The settlement was approved by the SCPSC on April 20, 2011 and is effective with the first billing cycle of May 2011.

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 (1) included implementation of an eWNA for SCE&G’s electric customers, which began in August 2010, (2) provided for a $25 million credit, over one year, to SCE&G’s customers to be offset by amortization of weather-related revenues which were deferred in the first quarter of 2010 pursuant to a stipulation between SCE&G and the ORS, (3) 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 and (4) provided for the recovery of certain federally-mandated capital expenditures that had been included in utility plant but were not being depreciated.

On July 15, 2010, the SCPSC issued an order approving the implementation by SCE&G of certain DSM Programs, including the establishment of an annual rider to allow recovery of the costs and lost net margin revenue associated with DSM Programs, along with an incentive for investing in such programs. The SCPSC’s order approved various settlement agreements among SCE&G, the ORS and other intervening parties. On July 27, 2010, SCE&G filed the DSM rate rider tariff sheet with the SCPSC. The tariff rider was applied to bills rendered on or after October 30, 2010. The order requires that SCE&G submit annual filings to the SCPSC regarding the DSM Programs, net lost revenues, program costs, incentive and net program benefits. In January 2011, SCE&G submitted to the SCPSC its annual update on DSM Programs. Included in the filing was a petition to update the rate rider to provide for the recovery of costs, lost net margin revenue, and the approved shared savings incentive for investing in such DSM Programs.

In December 2009, SCE&G submitted to the FERC revised tariff sheets to change the network and point to point transmission rates under SCE&G’s OATT. This initial request, if approved, would result in an annual revenue increase of approximately $5.6 million. In compliance with the OATT, on March 1, 2010 pursuant to an order issued by the FERC, SCE&G implemented, subject to refund, the proposed tariff sheets. On May 17, 2010, SCE&G submitted to the FERC as an informational filing its recalculated Annual Transmission Revenue Requirement or “Annual Update” for the period June 1, 2010 through May 31, 2011. The FERC accepted the tariff sheets in the “Annual Update” and made them effective, subject to refund, as of June 1, 2010.

Electric – BLRA

In January 2010, the SCPSC approved SCE&G’s request for an order pursuant to the BLRA to approve an updated construction and capital cost schedule for the construction of two new nuclear generating units at Summer Station. The updated schedule provides details of the construction and capital cost schedule beyond what was proposed and included in the original BLRA filing described below. The revised schedule does not change the previously announced completion date for the New Units or the originally announced cost.

In February 2009, the SCPSC 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, including contingencies, as approved by the SCPSC.

construct the new units. On November 15, 2010, SCE&G filed a petition to the SCPSC seeking an order approving an updated capital cost schedule that reflects the removal of the contingency reserve and incorporates presently identifiable capital costs of $173.9 million, and on March 28, 2011, SCE&G and the ORS entered into a settlement agreement which stated, among other things, that this updated capital cost schedule should be approved by the SCPSC. A hearing on this petition was held on April 4, 2011, and the SCPSC is expected to rule on the request in May 2011.

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%. In September 2009, the SCPSC approved SCE&G’s annual revised rate request under the BLRA which constituted a $22.5 million or 1.1% increase to retail electric rates. In October 2010, the SCPSC approved an increase of $47.3 million or 2.3%, under the BLRA for the annual revised rates adjustment filing. The new retail electric rates were effective for bills rendered on and after October 30, 2010.

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. On October 15, 2010, pursuant to the annual RSA filing, the SCPSC approved a decrease in retail natural gas rates of $10.4 million or approximately 2.1%. The rate adjustment was effective with the first billing cycle of November 2010.

SCE&G’s natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred including costs related to hedging natural gas purchasing activities. SCE&G’s gas rates are calculated using a methodology which adjusts 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 2010, before the SCPSC. The SCPSC issued an order in December 2010 finding that SCE&G’s gas purchasing policies and practices during the review period of August 1, 2009, through July 31, 2010, were reasonable and prudent.

In February 2011, the ORS submitted a request to the SCPSC to suspend SCE&G’s natural gas hedging program. SCE&G responded in March 2011 indicating no objection to the ORS’s request. The request is subject to approval by the SCPSC. The SCPSC issued an order directing staff to schedule an Oral Argument Information Briefing regarding this matter, which was held on April 21, 2011.

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

In October 2010, in connection with PSNC Energy’s 2010 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, 2010.

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.

	March 31,		December 31,
Millions of dollars	2011		2010
Regulatory Assets:
Accumulated deferred income taxes	$	210	$	210
Under-collections - electric fuel adjustment clause	36		25
Environmental remediation costs	31		32
AROs and related funding	304		298
Franchise agreements	44		45
Deferred employee benefit plan costs	323		326
Planned major maintenance	3		6
Deferred losses on interest rate derivatives	76		83
Other	39		36
Total Regulatory Assets	$	1,066	$	1,061

Regulatory Liabilities:
Accumulated deferred income taxes	$	25	$	26
Other asset removal costs	792		780
Storm damage reserve	38		38
Monetization of bankruptcy claim	37		37
Deferred gains on interest rate derivatives	26		26
Other	5		6
Total Regulatory Liabilities	$	923	$	913

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 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 in future periods. These amounts are expected to be recovered in retail electric rates during the period May 2012 through April 2013. SCE&G is allowed to recover 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 19 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 amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. 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 14 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 collected $8.5 million annually through July 15, 2010, through electric rates, to offset turbine maintenance expenditures. After July 15, 2010, SCE&G began collecting $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 swaps, treasury rate locks and forward starting swap agreements 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.

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

Other 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 first quarter of 2011 and 2010, SCE&G applied costs of $0.7 million 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, pending future SCPSC action.

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

The SCPSC or the NCUC (collectively, state public service commissions) or the FERC have reviewed and approved through specific orders most of the items shown as regulatory assets. Other regulatory assets include certain costs which have not been approved for recovery by a state public service commission or by the 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. 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 adverse effect on the Company’s results of operations, liquidity or financial position in the period the write-off would be recorded.

3. COMMON EQUITY

SCANA issued common stock valued at $25.4 million (at time of issue) during the three months ended March 31, 2011 through various compensation and dividend reinvestment plans (including the Stock Purchase Savings Plan), including the exercise of approximately 19,600 stock options during the period. In addition, in May 2010 SCANA entered into forward sale contracts for approximately 6.6 million common shares to be settled no later than February 29, 2012. There have been no shares issued under the forward sales contracts.

4. LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

In February 2011, PSNC Energy issued $150 million of 4.59% unsecured senior notes due February 14, 2021. Proceeds from these notes were used to retire $150 million of medium term notes due February 15, 2011.

In January 2011, SCE&G issued $250 million of 5.45% first mortgage bonds maturing on February 1, 2041. Proceeds from the sale were used to retire $150 million of First Mortgage Bonds due February 1, 2011, to repay short-term debt 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
	March 31,			December 31,			March 31,			December 31,			March 31,		December 31,
Millions of dollars	2011			2010			2011			2010			2011		2010
Lines of credit:
Committed long-term (a)
Total	$	300		$	300		$	1,100		$	1,100		$	100	$	100
LOC advances	-			-			-			-			-		-
Weighted average interest rate	-			-			-			-			-		-
Outstanding commercial paper (270 or fewer days)	$	26		$	39		$	486		$	381		-		-
Weighted average interest rate	.37		%	.35		%	.38		%	.42		%	-		-
Letters of credit supported by LOC	$	3		$	3		$	.3		$	.3		-		-
Available	$	271		$	258		$	614		$	719		$	100	$	100

(a) The Company’s committed long-term facilities serve to back-up the issuance of commercial paper or to provide liquidity support. Commercial paper can be issued in the amounts of up to $300 million by SCANA, $700 million by SCE&G, $400 million by Fuel Company and $100 million by PSNC Energy.

SCANA, SCE&G (including Fuel Company) and PSNC Energy are parties to five-year 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% 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%, 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%. 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 $71.4 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 2011.

5. INCOME TAXES

In the first quarter of 2010, in connection with a fuel cost recovery settlement (see Note 2), SCE&G accelerated the recognition of certain previously deferred state income tax credits. In the first quarter of 2011, pursuant to an SCPSC order, SCE&G continued the accelerated recognition of additional previously deferred state income tax credits (see Note 2). No other material changes in the status of the Company’s tax positions have occurred through March 31, 2011.

In connection with the change in method of accounting for certain repair costs in 2010, the Company identified approximately $36 million of unrecognized tax benefit. Because this method change is primarily a temporary difference, this additional benefit, if recognized, would not have a significant effect on the effective tax rate. Within the next 12 months, it is reasonably possible that this unrecognized tax benefit could increase by as much as $12 million or decrease by as much as $36 million. The events that could cause these changes are direct settlements with taxing authorities, legal or administrative guidance by relevant taxing authorities, or the lapse of an applicable statute of limitation.

The Company recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses. The Company has not accrued any significant amount of interest expense related to unrecognized tax benefits or tax penalties.

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.

The Company’s regulated gas operations (SCE&G and PSNC Energy) hedge natural gas purchasing activities using over-the-counter options and swaps and NYMEX futures and options. SCE&G’s tariffs include a PGA that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of SCE&G’s hedging activities are to be included in the PGA. As such, the cost of derivatives and gains and losses on such derivatives utilized to hedge gas purchasing activities are recoverable through the weighted average cost of gas calculation. The offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability. 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.

Interest Rate Swaps

The Company uses interest rate swaps to manage interest rate risk 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. Gains on certain swaps which were terminated prior to maturity of the underlying debt instruments are being amortized over the life of the debt they hedged.

The Company also uses swaps to synthetically convert variable rate debt to fixed rate debt. In addition, in anticipation of the issuance of debt, the Company may use treasury rate lock or forward starting swap agreements which 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. Ineffective portions of changes in fair value are recognized in income.

The effective portion of settlement payments made or received upon termination are amortized to interest expense over the term of the underlying debt and are classified as a financing activity in the condensed 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, 2011
Cash flow	-	3,640,000	17,236,375	20,876,375
Not designated (a)	8,470,000	-	22,857,305	31,327,305
Total (a)	8,470,000	3,640,000	40,093,680	52,203,680

As of December 31, 2010
Cash flow	-	5,715,000	17,190,351	22,905,351
Not designated (b)	10,677,000	-	20,588,581	31,265,581
Total (b)	10,677,000	5,715,000	37,778,932	54,170,932

(a) Includes an aggregate 8,950,000 DT related to basis swap contracts in Energy Marketing.

(b) Includes an aggregate 6,485,536 DT related to basis swap contracts in Energy Marketing.

At each of March 31, 2011 and December 31, 2010, the Company was party to interest rate swaps designated as fair value hedges with an aggregate notional amount of $556.4 million, and was party to interest rate swaps designated as cash flow hedges with an aggregate notional amount of $977.0 million and $1.1 billion, respectively.

The fair value of energy-related derivatives and interest rate derivatives was reflected in the 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, 2011
Derivatives designated as hedging instruments
Interest rate contracts	Prepayments and other	$	2	Other current liabilities	$	31
	Other deferred debits	4		Other deferred credits	20
Commodity contracts	Other current liabilities	1		Other current liabilities	3
				Other deferred credits	2
Total		$	7		$	56

Derivatives not designated as hedging instruments
Commodity contracts	Prepayments and other	$	3
Energy management contracts	Prepayments and other	5		Prepayments and other	$	1
	Other deferred debits	2		Other deferred debits	1
	Other deferred credits	1		Other current liabilities	4
				Other deferred credits	2
Total		$	11		$	8

As of December 31, 2010
Derivatives designated as hedging instruments
Interest rate contracts	Other current assets	$	1	Other current liabilities	$	57
	Other deferred debits	7		Other deferred credits	25
Commodity contracts	Other current liabilities	1		Other current liabilities	5
				Other deferred credits	2
Total		$	9		$	89

Derivatives not designated as hedging instruments
Commodity contracts	Prepayments and other	$	3
Energy management contracts	Prepayments and other	7		Prepayments and other	$	1
	Other deferred debits	2		Other current liabilities	6
				Other deferred credits	2
Total		$	12		$	9

(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.

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

Derivatives in Fair Value Hedging Relationships

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 reductions to interest expense of $2.5 million and $3.0 million for the three months ended March 31, 2011 and 2010, 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, 2011
Interest rate contracts	$	6		Interest expense	$	(1	)

Three Months Ended March 31, 2010
Interest rate contracts	$	3		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, 2011
Interest rate contracts	$	3		Interest expense	$	(1	)
Commodity contracts	(1		)	Gas purchased for resale	(4		)
Total	$	2			$	(5	)

Three Months Ended March 31, 2010
Interest rate contracts	$	(2	)	Interest expense	$	(1	)
Commodity contracts	(9		)	Gas purchased for resale	(4		)
Total	$	(11	)		$	(5	)

As of March 31, 2011, 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 $0.9 million as an increase to gas cost and approximately $2.1 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels. As of March 31, 2011, all of the Company’s commodity cash flow hedges settle by their terms before the end of 2013.

	Gain (Loss) Recognized in Income
Derivatives not designated as
Hedging Instruments
Millions of dollars	Location	2011		2010
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, 2011 and 2010.

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, 2011 and December 31, 2010, the Company has posted $19.7 million and $20.0 million, respectively, of collateral related to derivatives with contingent provisions that are in a net liability position. If all of the contingent features underlying these instruments were fully triggered as of March 31, 2011 and December 31, 2010, the Company would be required to post an additional $38.5 million and $74.0 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, 2011 and December 31, 2010 are $58.2 million and $94.0 million, respectively.

7. FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

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

		Fair Value Measurements Using
		Quoted Prices in Active		Significant Other
		Markets for Identical Assets		Observable Inputs
Millions of dollars		(Level 1)		(Level 2)
As of March 31, 2011
Assets -	Available for sale securities	$	3	$	-
	Interest rate contracts	-		6
	Commodity contracts	3		1
	Energy management contracts	-		8
Liabilities -	Interest rate contracts	-		51
	Commodity contracts	-		5
	Energy management contracts	-		8

As of December 31, 2010
Assets -	Available for sale securities	$	3	$	-
	Interest rate contracts	-		8
	Commodity contracts	2		2
	Energy management contracts	-		9
Liabilities -	Interest rate contracts	-		82
	Commodity contracts	1		6
	Energy management contracts	-		11

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, 2011 and December 31, 2010 were as follows:

	March 31, 2011				December 31, 2010
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	4,575.8	$	4,865.8	$	4,488.3	$	4,840.5

Fair values of long-term debt are based on quoted market prices of the instruments or similar instruments. For debt instruments for which no quoted market prices are available, fair values are based on net present value calculations. Carrying values reflect the fair values of interest rate swaps based on discounted cash flow models with independently sourced data. Early settlement of long-term debt may not be possible or may not be considered prudent. Potential taxes and other expenses that would be incurred in an actual sale or settlement have not been considered.

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	2011			2010			2011		2010
Three months ended March 31,
Service cost	$	4.6		$	4.7		$	1.1	$	1.1
Interest cost	11.1			11.8			3.0		3.0
Expected return on assets	(16.2		)	(16.4		)	-		-
Prior service cost amortization	1.8			1.9			0.3		0.3
Transition obligation amortization	-			-			0.2		0.2
Amortization of actuarial loss	3.0			4.3			0.1		0.1
Net periodic benefit cost	$	4.3		$	6.3		$	4.7	$	4.7

Prior to July 15, 2010, the SCPSC allowed SCE&G to defer as a regulatory asset the amount of pension cost exceeding amounts included in current rates for SCE&G’s retail electric and gas distribution regulated operations. In connection with the SCPSC’s July 2010 retail electric rate order and November 2010 natural gas RSA order, SCE&G began deferring all pension expense or income related to retail electric and gas operations as a regulatory asset or liability, as applicable. Costs totaling $2.3 million and $ 5.3 million were deferred for the three months ended March 31, 2011 and 2010, respectively.

9. COMMITMENTS AND CONTINGENCIES

Nuclear Insurance

The Price-Anderson Indemnification Act deals with public liability for a nuclear incident and establishes the liability limit for third-party claims associated with any nuclear incident at $12.6 billion. 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, would be $78.3 million per incident, but not more than $11.7 million per year.

SCE&G currently maintains policies (for itself and on behalf of Santee Cooper, a one-third owner of Summer Station) with Nuclear Electric Insurance Limited. The policies, covering the nuclear facility for property damage, excess property damage and outage costs, 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 $14.2 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 exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G 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 adverse impact on the Company’s results of operations, cash flows and financial position.

Environmental

SCE&G

In 2005, the EPA issued the CAIR, which requires 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. SCE&G has completed the installation of SCR technology at Cope Station for nitrogen oxide reduction, and GENCO has completed installation of a wet limestone scrubber at Williams Station for sulfur dioxide reduction. SCE&G also installed a wet limestone scrubber at Wateree Station. In July 2010, the EPA proposed a revised rule known as the Clean Air Transport Rule which will replace CAIR once promulgated. The proposed 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.

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 proposed rule provides up to four years for facilities to meet the standards once promulgated. The EPA is expected to finalize the rule in November 2011. The proposed 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. SCE&G anticipates that major remediation activities at these sites will continue until 2012 and will cost an additional $8.8 million. In addition, the National Park Service of the Department of the Interior has made an initial demand to SCE&G for payment of $9.1 million for certain costs and damages relating to the MGP site in Charleston, South Carolina. SCE&G expects to recover any cost arising from the remediation of these four sites through rates. At March 31, 2011, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $25.9 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 $3.6 million, which reflects its estimated remaining liability at March 31, 2011. PSNC Energy expects to recover through rates any costs allocable to PSNC Energy arising from the remediation of these sites.

Nuclear Generation

SCE&G, on behalf of itself and as agent for Santee Cooper has entered into a contractual agreement for the design and construction of two 1,117-MW nuclear generation units at the site of Summer Station. The contract provides that SCE&G and Santee Cooper will be joint owners and share operating costs and generation output of the New Units, 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. Assuming timely receipt of federal approvals and construction proceeding as scheduled, the first unit is expected to be completed and in service in 2016, and the second in 2019. SCE&G will be the operator of the New Units. SCE&G’s share of the estimated cash outlays (future value, excluding AFC) totals $5.5 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.

SCE&G’s latest Integrated Resource Plan filed with the SCPSC in February 2011 continues to support SCE&G’s need for 55 percent of the output of the two 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 more recently indicated that it will seek to reduce its 45 percent ownership in the New Units. Santee Cooper has disclosed that, in March 2011, it entered into a non-binding letter of intent with OUC that may result in the execution of a power purchase agreement with an option for OUC to acquire a portion of Santee Cooper’s ownership interest in the New Units. SCE&G is unable to predict whether any change in Santee Cooper’s ownership interest or the addition of new joint owners will increase project costs or delay the commercial operation dates of the New Units. Any such project cost increase or delay could be material.

10. SEGMENT OF BUSINESS INFORMATION

The Company’s reportable segments are listed in the following table. The Company uses operating income to measure profitability for its regulated operations; therefore, income available to common shareholders is not allocated to the Electric Operations and Gas Distribution segments. The Company uses income available to common shareholders 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. One of these nonreportable segments operates a FERC-regulated interstate pipeline company and the others conduct nonregulated operations in energy-related and telecommunications industries.

	External			Intersegment			Operating		Income Available to		Segment
Millions of dollars	Revenue			Revenue			Income		Common Shareholders		Assets
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

Three Months Ended March 31, 2010
Electric Operations	$	540		$	2		$	86	n/a		$	7,423
Gas Distribution	428			-			90		n/a		2,093
Retail Gas Marketing	262			-			n/a		$	30	219
Energy Marketing	196			47			n/a		-		99
All Other	8			97			5		-		1,262
Adjustments/Eliminations	(6		)	(146		)	49		97		1,046
Consolidated Total	$	1,428		$	-		$	230	$	127	$	12,142

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

SCANA CORPORATION

The following discussion should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations appearing in SCANA’s Annual Report on Form 10-K for the year ended December 31, 2010.

RESULTS OF OPERATIONS

FOR THE THREE MONTHS ENDED MARCH 31, 2011

AS COMPARED TO THE CORRESPONDING PERIODS IN 2010

Earnings Per Share

Earnings per share was as follows:

Millions of dollars	2011		2010
Basic and diluted earnings per share	$	1.00	$	1.02

Basic earnings per share decreased by $.10 due to lower gas margin, $.02 due to higher property taxes, $.02 due to higher depreciation expense, $.02 due to higher interest expense and by dilution from additional shares outstanding of $.03. These decreases were partially offset by $.16 due to higher electric margin and by $.01 due to lower operating expenses which are explained below.

Dividends Declared

SCANA’s Board of Directors has declared the following dividends on common stock during 2011:

Declaration Date	Dividend Per Share	Record Date	Payment Date
February 11, 2011	$.485	March 10, 2011	April 1, 2011
April 21, 2011	$.485	June 10, 2011	July 1, 2011

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	2011		% Change		2010
Operating revenues	$	560.3	3.5	%	$	541.6
Less: Fuel used in generation	212.6		(10.0	)%	236.1
Purchased power	2.3		(4.2	)%	2.4
Margin	$	345.4	14.0	%	$	303.1

Margin increased by $15.6 million due to higher SCPSC—approved retail electric base rates in July 2010, by $11.9 million due to an increase in base rates approved by the SCPSC under the BLRA in October 2010, and by $17.4 million as the result of a March 2010 settlement agreement approved by the SCPSC. (See also discussion at “Income Taxes”.) These increases were partially offset by $5.1 million due to lower residential and customer usage.

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

Classification (in thousands)	2011	% Change		2010
Residential	2,058	(10.5	)%	2,299
Commercial	1,650	(5.4	)%	1,744
Industrial	1,416	4.7	%	1,353
Sale for resale (excluding interchange)	477	11.7	%	427
Other	127	(1.6	)%	129
Total territorial	5,728	(3.8	)%	5,952
Negotiated Market Sales Tariff (NMST)	4	(33.3	)%	6
Total	5,732	(3.8	)%	5,958

Territorial sales volume decreased by approximately 360 MWh due to the effects of weather.

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	2011		% Change		2010
Operating revenues	$	359.8	(16.0	)%	$	428.3
Less: Gas purchased for resale	215.5		(22.8	)%	279.3
Margin	$	144.3	(3.2	)%	$	149.0

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

Classification (in thousands)	2011	% Change		2010
Residential	20,309	(17.2	)%	24,519
Commercial	10,350	(11.9	)%	11,743
Industrial	5,326	7.7	%	4,945
Transportation	9,574	4.0	%	9,202
Total	45,559	(9.6	)%	50,409

Margin at SCE&G decreased $4.5 million due to the SCPSC-approved decrease in retail gas base rates under the RSA which became effective with the first billing cycle of November 2010. 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 income available to common shareholders were as follows:

Millions		2011	% Change			2010
Operating revenues	$	202.4	(22.8	)%	$	262.1
Income available to common shareholders		21.6	(27.3	)%		29.7

Operating revenues decreased as a result of milder weather in 2011. Income available to common shareholders decreased primarily as a result of lower margin, partially offset by lower bad debt expense.

Energy Marketing

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

Millions		2011	% Change			2010
Operating revenues	$	203.6	(16.4	)%	$	243.4
Income available to common shareholders		1.2	*			0.5

*Greater than 100%

Operating revenues decreased primarily due to lower market prices. Income available to common shareholders increased primarily due to higher margins on sales.

Other Operating Expenses

Other operating expenses were as follows:

Millions of dollars		2011	% Change			2010
Other operation and maintenance	$	169.7	(1.3)	%	$	172.0
Depreciation and amortization		85.8	3.6	%		82.8
Other taxes		51.8	8.6	%		47.7

Other operation and maintenance expenses decreased by $1.2 million due to lower generation, transmission and distribution expenses and by $4.6 million due to lower customer service expenses and general expenses, including bad debt expense. This decrease was partially offset by $4.0 million due to higher compensation and other benefits. Depreciation and amortization expense increased in 2011 primarily due to net property additions. 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.

Pension Cost

Pension cost was recorded on the Company’s income statements and balance sheets as follows:

Millions of dollars		2011		2010
Income Statement Impact:
Employee benefit costs	$	0.7	$	(0.1	)
Other income		0.1		(0.9	)
Balance Sheet Impact:
Capital expenditures		0.9		1.6
Component of amount due from Summer Station co-owner		0.3		0.4
Regulatory asset		2.3		5.3
Total Pension Cost	$	4.3	$	6.3

No contribution to the pension trust will be necessary in or for 2011, nor will limitations on benefit payments apply. Prior to July 15, 2010, the SCPSC allowed SCE&G to defer as a regulatory asset the amount of pension cost exceeding amounts included in rates for its retail electric and gas distribution regulated operations. In connection with the SCPSC’s July 2010 electric rate order and November 2010 natural gas RSA order, SCE&G began deferring all pension expense and income related to retail electric and gas operations as a regulatory asset or regulatory liability, as applicable. These costs will be deferred until such time as future rate recovery is provided for by the SCPSC.

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. AFC related to the construction of two nuclear electric generation units at the site of Summer Station was offset by the decrease in AFC related to the completion of certain pollution abatement projects at coal fired plants.

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, 2011 were higher than the same period in 2010 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 pursuant to the settlement of a fuel cost recovery proceeding in the first quarter of 2010 (see also the discussion at “Electric Operations”).

LIQUIDITY AND CAPITAL RESOURCES

The Company anticipates that its contractual cash obligations, including its $587 million current portion of long-term debt as of March 31, 2011, 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 further 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, 2011 was 3.57 and 2.95, respectively.

	SCANA						SCE&G						PSNC Energy
	March 31,			December 31,			March 31,			December 31,			March 31,		December 31,
Millions of dollars	2011			2010			2011			2010			2011		2010
Lines of credit:
Committed long-term (a)
Total	$	300		$	300		$	1,100		$	1,100		$	100	$	100
LOC advances	-			-			-			-			-		-
Weighted average interest rate	-			-			-			-			-		-
Outstanding commercial paper (270 or fewer days)	$	26		$	39		$	486		$	381		-		-
Weighted average interest rate	.37		%	.35		%	.38		%	.42		%	-		-
Letters of credit supported by LOC	$	3		$	3		$	.3		$	.3		-		-
Available	$	271		$	258		$	614		$	719		$	100	$	100

(a) The Company’s committed long-term facilities serve to back-up the issuance of commercial paper or to provide liquidity support. Commercial paper can be issued in amounts of up to $300 million by SCANA, $700 million by SCE&G, $400 million by Fuel Company and $100 million by PSNC Energy.

At March 31, 2011, the Company had net available liquidity of approximately $1.1 billion. The Company regularly monitors the commercial paper and short-term credit markets to optimize the timing of repayment of any outstanding balance on its draws, while maintaining appropriate levels of liquidity. The Company’s long-term debt portfolio has a weighted average maturity of approximately 16 years and bears an average cost of 6.3%. A significant majority of long-term debt, other than credit facility draws, 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 stock valued at $25.4 million during the three months ended March 31, 2011 through various compensation and dividend reinvestment plans. In addition, the Company expects to issue approximately 6.6 million common shares under forward sales contracts to be settled no later than February 29, 2012, resulting in net proceeds of approximately $200 million.

The Company’s liquidity will be favorably impacted due to the recent issuance of final rules by the IRS related to bonus depreciation. In addition the Company recognizes a cash benefit from the method being used to account for capital maintenance, which results in certain maintenance costs being treated as current expense for income tax purposes. The Company expects these strategies to generate approximately $60 million in cash flow for 2011.

OTHER MATTERS

Nuclear Generation

SCE&G, on behalf of itself and as agent for Santee Cooper, has entered into a contractual agreement for the design and construction of two 1,117-MW nuclear generation units at the site of Summer Station. The contract provides that SCE&G and Santee Cooper will be joint owners and share operating costs and generation output of the New Units, 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. Assuming timely receipt of federal approvals and construction proceeding as scheduled, the first unit is expected to be completed and in service in 2016, and the second in 2019. SCE&G will be the operator of the New Units. SCE&G’s share of the estimated cash outlays (future value, excluding AFC) totals $5.5 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.

In March 2011 a tsunami resulting from a massive earthquake severely damaged several nuclear generating units and their back-up cooling systems in Japan. The impact of the disaster is being evaluated world-wide, and numerous political and regulatory bodies, including those in the United States, are seeking to determine if additional safety measures should be required at other existing nuclear facilities, as well as those planned for construction. SCE&G cannot predict what regulatory or other outcomes may be implemented in the United States, nor how such initiatives would impact SCE&G’s existing Summer Station or the licensing, construction or operations of the New Units.

In April 2011, the NRC and the USACE completed the FEIS for the New Units, concluding that there were no environmental impacts that would preclude issuing the COL for the New Units. The NRC continues to compile its final safety evaluation report, which is expected to be completed in the summer of 2011.

Fuel Contract

On January 27, 2011, SCE&G, for itself and as agent for Santee Cooper, and Westinghouse entered into a fuel alliance agreement and contracts for fuel fabrication and related services. Under these contracts, Westinghouse will supply enriched nuclear fuel assemblies for Summer Station Unit 1 and the New Units. Westinghouse will be SCE&G’s exclusive provider of such fuel assemblies on a cost-plus basis. The fuel assemblies to be delivered under the contracts are expected to supply the nuclear fuel requirements of Summer Station Unit 1 and the New Units through 2033. SCE&G is dependent upon Westinghouse for providing fuel assemblies for the new AP1000 passive reactors in the New Units in the current and anticipated future absence of other commercially viable sources. Westinghouse currently provides maintenance and engineering support to Summer Station Unit 1 under a services alliance arrangement, and SCE&G has also contracted for Westinghouse to provide similar support services to the New Units upon their completion and commencement of commercial operation in 2016 and 2019, respectively.

Air Quality

SCE&G

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, EPA proposed new standards for mercury and other specified air pollutants. The proposed rule provides up to four years for facilities to meet the standards once promulgated. The EPA is expected to finalize the rule in November 2011. The proposed 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.

PSNC Energy

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, 2010. 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
2011	Long	2011	(Long)
Settlement Price (a)	4.59	Strike Price (a)	5.15
Contract Amount (b)	17.1	Contract Amount (b)	31.5
Fair Value (b)	16.9	Fair Value (b)	1.8

2012		2012
Settlement Price (a)	5.05	Strike Price (a)	5.26
Contract Amount (b)	3.8	Contract Amount (b)	12.4
Fair Value (b)	3.8	Fair Value (b)	1.1

(a) Weighted average, in dollars
(b) Millions of dollars

Swaps	2011	2012	2013	2014	2015
Commodity Swaps:
Pay fixed/receive variable (b)	36.1	27.6	15.8	5.2	5.2
Average pay rate (a)	5.2285	5.6706	5.8365	5.4031	5.4031
Average received rate (a)	4.6303	5.0610	5.4063	5.7336	6.0807
Fair value (b)	32.0	24.7	14.6	5.5	5.8

Pay variable/receive fixed (b)	27.9	18.8	11.9	5.5	5.8
Average pay rate (a)	4.5920	5.0504	5.4048	5.7336	6.0807
Average received rate (a)	5.0895	5.5855	5.4331	5.4150	5.4150
Fair value (b)	31.0	20.8	12.0	5.2	5.2

Basis Swaps:
Pay variable/receive variable (b)	21.0	18.2	4.6
Average pay rate (a)	4.6214	5.0823	5.5072
Average received rate (a)	4.6098	5.0644	5.4550
Fair value (b)	20.9	18.1	4.5

(a) Weighted average, in dollars
(b) Millions of dollars

ITEM 4. CONTROLS AND PROCEDURES

As of March 31, 2011, 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, 2011, 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, 2011 that has materially affected or is reasonably likely to materially affect SCANA’s internal control over financial reporting.

SOUTH CAROLINA ELECTRIC & GAS COMPANY

FINANCIAL SECTION

ITEM 1. FINANCIAL STATEMENTS

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31,			December 31,
Millions of dollars	2011			2010
Assets

Utility Plant In Service	$	10,148		$	10,112
Accumulated Depreciation and Amortization	(3,137		)	(3,098		)
Construction Work in Progress	1,181			1,051
Nuclear Fuel, Net of Accumulated Amortization	128			133
Utility Plant, Net ($627 and $634 related to VIEs)	8,320			8,198

Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	46			46
Assets held in trust, net - nuclear decommissioning	78			76
Other investments	5			4
Nonutility Property and Investments, Net	129			126

Current Assets:
Cash and cash equivalents	24			31
Receivables, net of allowance for uncollectible accounts of $2 and $3	400			507
Inventories (at average cost):
Fuel and gas supply	219			216
Materials and supplies	117			117
Emission allowances	5			6
Prepayments and other	108			168
Deferred income taxes	15			15
Total Current Assets ($223 and $221 related to VIEs)	888			1,060

Deferred Debits and Other Assets:
Pension asset	58			57
Regulatory assets	1,002			996
Other	138			137
Total Deferred Debits and Other Assets ($44 and $43 related to VIEs)	1,198			1,190
Total	$	10,535		$	10,574

	March 31,		December 31,
Millions of dollars	2011		2010
Capitalization and Liabilities

Common equity	$	3,479	$	3,436
Noncontrolling interest	105		105
Long-Term Debt, net	3,128		3,037
Total Capitalization	6,712		6,578

Current Liabilities:
Short-term borrowings	486		381
Current portion of long-term debt	22		22
Accounts Payable	174		341
Affiliated Payables	154		140
Customer deposits and customer prepayments	60		60
Taxes accrued	41		137
Interest accrued	48		50
Dividends declared	51		54
Derivative financial instruments	7		34
Other	66		80
Total Current Liabilities	1,109		1,299

Deferred Credits and Other Liabilities:
Deferred income taxes, net	1,248		1,240
Deferred investment tax credits	49		56
Asset retirement obligations	484		478
Pension and other postretirement benefits	163		163
Regulatory liabilities	669		662
Other	101		98
Total Deferred Credits and Other Liabilities	2,714		2,697
Commitments and Contingencies (Note 9)	-		-
Total	$	10,535	$	10,574

See Notes to Condensed Consolidated Financial Statements.

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended
	March 31,
Millions of dollars	2011			2010
Operating Revenues:
Electric	$	560		$	542
Gas	144			180
Total Operating Revenues	704			722

Operating Expenses:
Fuel used in electric generation	213			236
Purchased power	2			2
Gas purchased for resale	88			119
Other operation and maintenance	132			132
Depreciation and amortization	71			66
Other taxes	47			44
Total Operating Expenses	553			599

Operating Income	151			123

Other Income (Expense):
Other income	1			4
Other expenses	(4		)	(3		)
Interest charges, net of allowance for borrowed funds used during construction of $2 and $2	(50		)	(47		)
Allowance for equity funds used during construction	3			3
Total Other Expense	(50		)	(43		)

Income Before Income Tax Expense	101			80
Income Tax Expense	31			16

Net Income	70			64
Less Net Income Attributable to Noncontrolling Interest	2			2

Earnings Available to Common Shareholder	$	68		$	62

Dividends Declared on Common Stock	$	51		$	47

See Notes to Condensed Consolidated Financial Statements.

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended
	March 31,
Millions of dollars	2011			2010
Cash Flows From Operating Activities:
Net income	$	70		$	64
Adjustments to reconcile net income to net cash provided from operating activities:
Deferred income taxes, net	8			10
Depreciation and amortization	74			70
Amortization of nuclear fuel	9			9
Allowance for equity funds used during construction	(3		)	(3		)
Carrying cost recovery	-			(1		)
Cash provided (used) by changes in certain assets and liabilities:
Receivables	107			13
Inventories	(13		)	7
Prepayments and other	59			7
Regulatory assets	13			(31		)
Regulatory liabilities	(1		)	3
Accounts payable	(67		)	(15		)
Taxes accrued	(96		)	(73		)
Interest accrued	(2		)	(3		)
Changes in other assets	(4		)	(9		)
Changes in other liabilities	(36		)	29
Net Cash Provided From Operating Activities	118			77
Cash Flows From Investing Activities:
Utility property additions and construction expenditures	(269		)	(197		)
Proceeds from investments and sale of assets	1			4
Nonutility property additions	-			(1		)
Investment in affiliate	-			41
Purchase of investments	(2		)	(1		)
Net Cash Used For Investing Activities	(270		)	(154		)
Cash Flows From Financing Activities:
Proceeds from issuance of long-term debt	229			50
Repayment of long-term debt	(157		)	(9		)
Dividends	(54		)	(50		)
Contributions from parent	24			25
Short-term borrowings –affiliate, net	(2		)	19
Short-term borrowings, net	105			(38		)
Net Cash Provided From (Used For) Financing Activities	145			(3		)
Net Decrease In Cash and Cash Equivalents	(7		)	(80		)
Cash and Cash Equivalents, January 1	31			134
Cash and Cash Equivalents, March 31	$	24		$	54
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $2 and $2)	$	47		$	47
- Income taxes	-			-

Noncash Investing and Financing Activities:
Accrued construction expenditures	84			95

See Notes to Condensed Consolidated Financial Statements.

SOUTH CAROLINA ELECTRIC & GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended
	March 31,
Millions of dollars	2011			2010
Net Income	$	70		$	64
Other Comprehensive Income, net of tax:
Reclassification to net income - amortization of deferred employee benefit plan costs, net of taxes	-			1
Total Comprehensive Income	70			65
Less comprehensive income attributable to noncontrolling interest	(2		)	(2		)
Comprehensive income available to common shareholder (1)	$	68		$	63

(1) Accumulated other comprehensive loss totaled $2.6 million as of March 31, 2011 and $2.7 million as of December 31, 2010.

See Notes to Condensed Consolidated Financial Statements.

SOUTH CAROLINA ELECTRIC & GAS COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 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, 2010. 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 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 $499 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

2. RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric

Electric – BLRA

In May 2009, two intervenors filed separate appeals of the order with the South Carolina Supreme Court. With regard to the first appeal, which challenged the SCPSC’s prudency finding, the South Carolina Supreme Court issued an opinion on April 26, 2010, affirming the decision of the SCPSC. As for the second appeal, the South Carolina Supreme Court reversed the SCPSC’s decision to allow SCE&G to include a pre-approved cost contingency fund and associated inflation (contingency reserve) as part of its anticipated capital costs allowed under the BLRA. SCE&G’s share of the project, as originally approved by the SCPSC, is $4.5 billion in 2007 dollars. Approximately $438 million represented contingency costs associated with the project. Without the pre-approved contingency reserve, SCE&G must seek SCPSC approval for the recovery of any additional capital costs. The Court’s ruling, however, does not affect the project schedule or disturb the SCPSC’s issuance of a certificate of environmental compatibility and public convenience and necessity, which is required to construct the new units. On November 15, 2010, SCE&G filed a petition to the SCPSC seeking an order approving an updated capital cost schedule that reflects the removal of the contingency reserve and incorporates presently identifiable capital costs of $173.9 million and, on March 28, 2011, SCE&G and the ORS entered into a settlement agreement which stated, among other things, that this updated capital cost schedule should be approved by the SCPSC. A hearing on this petition was held on April 4, 2011, and the SCPSC is expected to rule on the request in May 2011.

Gas

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.

	March 31,		December 31,
Millions of dollars	2011		2010
Regulatory Assets:
Accumulated deferred income taxes	$	205	$	205
Under collections – electric fuel adjustment clause	36		25
Environmental remediation costs	26		27
AROs and related funding	289		284
Franchise agreements	44		45
Deferred employee benefit plan costs	287		288
Planned major maintenance	3		6
Deferred losses on interest rate derivatives	76		83
Other	36		33
Total Regulatory Assets	$	1,002	$	996

Regulatory Liabilities:
Accumulated deferred income taxes	$	25	$	26
Other asset removal costs	577		568
Storm damage reserve	38		38
Deferred gains on interest rate derivatives	26		26
Other	3		4
Total Regulatory Liabilities	$	669	$	662

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 approximately 19 years.

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

Other 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 first quarter of 2011 and 2010, SCE&G applied costs of $0.7 million 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, pending future SCPSC action.

The SCPSC or the FERC have reviewed and approved through specific orders most of the items shown as regulatory assets. Other regulatory assets include 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. 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 adverse effect on Consolidated SCE&G’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, 2011 and 2010 were as follows:

Millions of dollars	Common Equity			Noncontrolling Interest			Total Equity
Balance at January 1, 2011	$	3,436		$	105		$	3,541
Capital contribution from parent	24			-			24
Dividends declared	(49		)	(2		)	(51		)
Net income	68			2			70
Balance as of March 31, 2011	$	3,479		$	105		$	3,584

Balance at January 1, 2010	$	3,162		$	97		$	3,259
Capital contribution from parent	25			-			25
Dividends declared	(45		)	(2		)	(47		)
Net income	62			2			64
Balance as of March 31, 2010	$	3,204		$	97		$	3,301

4. LONG-TERM DEBT AND LIQUIDITY

Long-term Debt

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:

	Consolidated SCE&G
	March 31,			December 31,
Millions of dollars	2011			2010
Lines of credit:
Committed long-term (a)
Total	$	1,100		$	1,100
LOC advances	-			-
Weighted average interest rate	-			-
Outstanding commercial paper (270 or fewer days)	$	486		$	381
Weighted average interest rate	.38		%	.42		%
Letters of credit supported by LOC	$	.3		$	.3
Available	$	614		$	719

(a) Consolidated SCE&G’s committed long-term facilities serve to back-up the issuance of commercial paper or to provide liquidity support. SCE&G and Fuel Company have commercial paper programs in the amounts of up to $700 million and $400 million, respectively. SCE&G has guaranteed the short-term borrowings of Fuel Company.

SCE&G (including Fuel Company) are parties to five-year 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% 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%, 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%. 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 $71.4 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 2011.

5. INCOME TAXES

In the first quarter of 2010, in connection with a fuel cost recovery settlement (see Note 2), SCE&G accelerated the recognition of certain previously deferred state income tax credits. In the first quarter of 2011, pursuant to an SCPSC order, SCE&G continued the accelerated recognition of additional previously deferred state income tax credits (see Note 2). No other material changes in the status of Consolidated SCE&G’s tax positions have occurred through March 31, 2011.

In connection with the change in method of accounting for certain repair costs in 2010, SCE&G identified approximately $36 million of unrecognized tax benefit. Because this method change is primarily a temporary difference, this additional benefit, if recognized, would not have a significant effect on the effective tax rate. Within the next 12 months, it is reasonably possible that this unrecognized tax benefit could increase by as much as $12 million or decrease by as much as $36 million. The events that could cause these changes are direct settlements with taxing authorities, legal or administrative guidance by relevant taxing authorities, or the lapse of an applicable statute of limitation.

Consolidated SCE&G recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses. Consolidated SCE&G has not accrued any significant amount of interest expense related to unrecognized tax benefits or tax penalties.

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.

SCE&G’s tariffs include a PGA that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of these hedging activities are to be included in the PGA. As such, the cost of derivatives and gains and losses on such derivatives utilized to hedge gas purchasing activities are recoverable through the weighted average cost of gas calculation. The offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability. These derivative financial instruments are not designated as hedges for accounting purposes.

Interest Rate Swaps

Consolidated SCE&G uses interest rate swaps to manage interest rate risk on certain debt issuances and to synthetically convert variable rate debt to fixed rate debt. In addition, in anticipation of the issuance of debt, Consolidated SCE&G may use treasury rate lock or forward starting swap agreements which 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. Ineffective portions of changes in fair value are recognized in income.

The effective portions of settlement payments made or received upon termination are amortized to interest expense over the term of the underlying debt and are classified as a financing activity in the condensed consolidated statements of cash flows.

Quantitative Disclosures Related to Derivatives

SCE&G was party to natural gas derivative contracts for 1,960,000 DT at March 31, 2011 and 2,460,000 DT at December 31, 2010. Consolidated SCE&G was a party to interest rate swaps designated as cash flow hedges with an aggregate notional amount of $321.4 million at March 31, 2011 and $421.4 million at December 31, 2010.

The fair value of energy-related derivatives and interest rate derivatives was reflected in the 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, 2011
Derivatives designated as hedging instruments
Interest rate contracts	Other deferred debits	$	4	Other current liabilities	$	6
				Other deferred credits	4
Total		$	4		$	10

Derivatives not designated as hedging instruments
Commodity contracts	Prepayments and other	$	1

As of December 31, 2010
Derivatives designated as hedging instruments
Interest rate contracts	Other deferred debits	$	4	Other current liabilities	$	34
				Other deferred credits	1
Total		$	4		$	35

Derivatives not designated as hedging instruments
Commodity contracts	Prepayments and other	$	1

(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 with the same counterparty are reported as either a net asset or liability.

The effect of derivative instruments on the 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, 2011
Interest rate contracts	$	6	Interest expense	$	(1	)

Three Months Ended March 31, 2010
Interest rate contracts	$	3	Interest expense	$	(1	)

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

Three Months Ended March 31, 2010
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, 2011 and 2010.

Credit Risk Considerations

Certain of Consolidated SCE&G’s derivative instruments contain contingent provisions that require collateral to be provided upon the occurrence of specific events, primarily credit downgrades. As of March 31, 2011 and December 31, 2010, Consolidated SCE&G has posted no collateral, respectively, related to derivatives with contingent provisions that are in a net liability position. If all of the contingent features underlying these instruments were fully triggered as of March 31, 2011 and December 31, 2010, Consolidated SCE&G would be required to post $10.4 million and $34.9 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, 2011 and December 31, 2010 is $10.4 million and $34.9 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 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		Significant Other
		Markets for Identical Assets		Observable Inputs
Millions of dollars		(Level 1)		(Level 2)
As of March 31, 2011
Assets -	Interest rate contracts	$	-	$	4
	Commodity contracts	1		-
Liabilities-	Interest rate contracts	-		10

As of December 31, 2010
Assets -	Interest rate contracts	$	-	$	4
	Commodity contracts	1		-
Liabilities -	Interest rate contracts	-		35

Financial instruments for which the carrying amount may not equal estimated fair value at March 31, 2011 and December 31, 2010 were as follows:

	March 31, 2011				December 31, 2010
Millions of dollars	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	3,150.1	$	3,365.9	$	3,059.7	$	3,321.8

Potential taxes and other expenses that would be incurred in an actual sale or settlement have not been considered.

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	2011			2010			2011		2010
Three months ended March 31,
Service cost	$	3.7		$	3.5		$	0.9	$	0.8
Interest cost	9.4			10.2			2.4		2.4
Expected return on assets	(13.8		)	(14.5		)	-		-
Prior service cost amortization	1.5			1.6			0.2		0.2
Transition obligation amortization	-			-			-		-
Amortization of actuarial loss	2.6			4.2			-		0.1
Net periodic benefit cost	$	3.4		$	5.0		$	3.5	$	3.5

Prior to July 15, 2010, the SCPSC allowed SCE&G to defer as a regulatory asset the amount of pension cost exceeding amounts included in current rates for SCE&G’s retail electric and gas distribution regulated operations. In connection with the SCPSC’s July 2010 retail electric rate order and November 2010 natural gas RSA order, SCE&G began deferring all pension expense or income related to retail electric and gas operations as a regulatory asset or liability, as applicable. Costs totaling $2.3 million and $5.3 million were deferred for the three months ended March 31, 2011 and 2010, respectively.

9. COMMITMENTS AND CONTINGENCIES

Nuclear Insurance

Environmental

Nuclear Generation

SCE&G, on behalf of itself and as agent for Santee Cooper has entered into a contractual agreement for the design and construction of two 1,117-MW nuclear generation units at the site of Summer Station. The contract provides that SCE&G and Santee Cooper will be joint owners and share operating costs and generation output of the New Units, 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. Assuming timely receipt of federal approvals and construction proceeding as scheduled, the first unit is expected to be completed and in service in 2016, and the second in 2019. SCE&G will be the operator of the New Units. SCE&G’s share of the estimated cash outlays (future value, excluding AFC) totals $5.5 billion for plant costs and for related transmission infrastructure costs, which costs are projected based on historical one-year and five year escalation rates as required by the SCPSC.

10. AFFILIATED TRANSACTIONS

CGT transports natural gas to SCE&G to supply certain electric generation requirements and to serve SCE&G’s retail gas customers. SCE&G had approximately $2.7 million and $2.1 million payable to CGT for transportation services at March 31, 2011 and December 31, 2010, respectively.

SCE&G purchases natural gas and related pipeline capacity from SEMI to supply its Jasper County Electric Generating Station, Urquhart Electric Generation Station and to serve its retail gas customers. Such purchases totaled approximately $45.4 million and $47.3 million for the three months ended March 31, 2011 and 2010, respectively. SCE&G’s payables to SEMI for such purposes were $15.5 million and $16.1 million as of March 31, 2011 and December 31, 2010, respectively.

SCE&G owns 40% of Canadys Refined Coal, LLC and 10% of Cope Refined Coal, LLC, both involved in the manufacturing and selling of refined coal to reduce emissions. SCE&G accounts for these investments using the equity method. SCE&G’s receivables from these affiliates were $5.0 million at March 31, 2011 and insignificant at December 31, 2010. SCE&G’s payables to these affiliates were $5.1 million at March 31, 2011 and insignificant at December 31, 2010. SCE&G’s total purchases were $13.0 million and $12.5 million for the three months ended March 31, 2011 and 2010, respectively. SCE&G’s total sales were $12.9 million and $12.4 million for the three months ended March 31, 2011 and 2010, 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, 2011 or 2010. At March 31, 2011 and December 31, 2010, Consolidated SCE&G owed an affiliate $69.0 million and $71.0 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.

			Operating			Earnings Available
	External		Income			to Common		Segment
Millions of Dollars	Revenue		(Loss)			Shareholder		Assets
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

Three Months Ended March 31, 2010
Electric Operations	$	542	$	86		n/a		$	7,423
Gas Distribution	180		37			n/a		564
Adjustments/Eliminations	-		-			$	62	1,800
Consolidated Total	$	722	$	123		$	62	$	9,787

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, 2010.

RESULTS OF OPERATIONS

FOR THE THREE MONTHS ENDED MARCH 31, 2011

AS COMPARED TO THE CORRESPONDING PERIOD IN 2010

Net Income

Net income for Consolidated SCE&G was as follows:

Millions of dollars	2011		% Change		2010
Net income	$	67.8	9.2	%	$	62.1

Net income increased by $15.3 million due to higher electric margin. These increases were partially offset by lower gas margin of $3.4 million, higher depreciation expense of $2.1 million, higher property taxes of $2.3 million and higher interest expense of $1.6 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 2011:

Declaration Date	Amount	Quarter Ended	Payment Date
February 11, 2011	$50.6 million	March 31, 2011	April 1, 2011
April 21, 2011	49.0 million	June 30, 2011	July 1, 2011

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	2011		% Change		2010
Operating revenues	$	560.3	3.5	%	$	541.6
Less: Fuel used in electric generation	212.6		(10.0	)%	236.1
Purchased power	2.3		(4.2	)%	2.4
Margin	$	345.4	14.0	%	$	303.1

Margin increased by $15.6 million due to higher SCPSC–approved retail electric base rates in July 2010, by $11.9 million due to an increase in base rates approved by the SCPSC under the BLRA in October 2010, and by $17.4 million as the result of a March 2010 settlement agreement approved by the SCPSC. (See also discussion at “Income Taxes”.) These increases were partially offset by $5.1 million due to lower residential and customer usage.

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

Classification (in thousands)	2011	% Change		2010
Residential	2,058	(10.5	)%	2,299
Commercial	1,650	(5.4	)%	1,744
Industrial	1,416	4.7	%	1,353
Sale for resale (excluding interchange)	477	11.7	%	427
Other	127	(1.6	)%	129
Total territorial	5,728	(3.8	)%	5,952
Negotiated Market Sales Tariff (NMST)	4	(33.3	)%	6
Total	5,732	(3.8	)%	5,958

Territorial sales volume decreased by approximately 360 MWh due to the effects of weather.

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	2011		% Change		2010
Operating revenues	$	144.1	(20.2	)%	$	180.6
Less: Gas purchased for resale	87.8		(26.1	)%	118.8
Margin	$	56.3	(8.9	)%	$	61.8

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

Classification (in thousands)	2011	% Change		2010
Residential	6,532	(21.4	)%	8,309
Commercial	4,277	(10.8	)%	4,797
Industrial	4,467	11.4	%	4,010
Transportation	1,192	16.3	%	1,025
Total	16,468	(9.2	)%	18,141

Margin decreased $4.5 million due to the SCPSC-approved decrease in retail gas base rates under the RSA which became effective with the first billing cycle of November 2010. Total sales volumes decreased primarily due to decreased firm customer usage resulting from milder weather.

Other Operating Expenses

Other operating expenses were as follows:

Millions of dollars	2011		% Change		2010
Other operation and maintenance	$	132.0	-		$	132.0
Depreciation and amortization	70.9		6.8	%	66.4
Other taxes	47.4		8.7	%	43.6

Other operation and maintenance expenses were unchanged. Other operation and maintenance expenses increased by $4.5 million due to higher compensation and other benefits. These increases were offset by $1.3 million due to lower generation, transmission and distribution expenses and by $0.7 million due to lower customer service expenses and general expenses, including bad debt expense. Depreciation and amortization expense increased in 2011 primarily due to net property additions. Other taxes increased primarily due to higher property taxes.

Other Income (Expense)

Other income (expense) includes the results of certain incidental (non-utility) activities. Other income (expense) decreased in 2011 compared to 2010 primarily due to the July 2010 SCPSC order allowing the recovery of certain federally mandated capital expenditures and the related cessation of recording of carrying cost recovery.

Pension Cost

Pension cost was recorded on Consolidated SCE&G’s income statements and balance sheets as follows:

Millions of dollars	2011		2010
Income Statement Impact:
Employee benefit costs	$	-	$	(1.1	)
Other income	-		(1.0		)
Balance Sheet Impact:
Capital expenditures	0.8		1.4
Component of amount due from Summer Station co-owner	0.3		0.4
Regulatory asset	2.3		5.3
Total Pension Cost	$	3.4	$	5.0

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. AFC related to the construction of two nuclear electric generation units at the site of Summer Station was offset by the decrease in AFC related to the completion of certain pollution abatement projects at coal fired plants.

Interest Expense

Interest charges increased primarily due to increased borrowings.

Income Taxes

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 further 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, 2011 was 2.95 and 3.27, 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:

	Consolidated SCE&G
		March 31,			December 31,
Millions of dollars		2011			2010
Lines of credit:
Committed long-term (a)
Total	$	1,100		$	1,100
LOC advances		-			-
Weighted average interest rate		-			-
Outstanding commercial paper (270 or fewer days)	$	486		$	381
Weighted average interest rate		.38	%		.42	%
Letters of credit supported by LOC	$	.3		$	.3
Available	$	614		$	719

(a) Consolidated SCE&G’s committed long-term facilities serve to back-up the issuance of commercial paper or to provide liquidity support. SCE&G and Fuel Company have commercial paper programs in the amounts of up to $700 million and $400 million, respectively. Nuclear and fossil fuel inventories and emission allowances are financed through the issuance by Fuel Company of short-term commercial paper or LOC advances.

At March 31, 2011, Consolidated SCE&G had net available liquidity of approximately $638 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, 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 6.2%. A significant portion of long-term debt, other than credit facility draws, 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.

Consolidated SCE&G’s liquidity will be favorably impacted due to the recent issuance of final rules by the IRS related to bonus depreciation. In addition Consolidated SCE&G recognizes a cash benefit from the method being used to account for capital maintenance, which results in certain maintenance costs being treated as current expense for income tax purposes. Consolidated SCE&G expects these strategies to generate approximately $60 million in cash flow for 2011. In addition, in 2011 SCE&G has received capital contributions from SCANA of approximately $24 million and expects to receive an additional $70 million related to SCANA’s issuance of stock through various compensation and dividend reinvestment plans.

OTHER MATTERS

Nuclear Generation

Fuel Contract

Air Quality

In 2005, the EPA issued the CAIR, which requires 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. SCE&G has completed the installation of SCR technology at Cope Station for nitrogen oxide reduction, and GENCO has completed installation of a wet limestone scrubber at Williams Station for sulfur dioxide reduction. SCE&G also installed a wet limestone scrubber at Wateree Station. In July 2010, EPA proposed a revised rule known as the Clean Air Transport Rule which will replace CAIR once promulgated. The proposed 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.

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, EPA proposed new standards for mercury and other specified air pollutants. The proposed rule provides up to four years for facilities to meet the standards once promulgated. The EPA is expected to finalize the rule in November 2011. The proposed 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.

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, 2010. 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
2011	(Long)
Strike Price (a)	4.77
Contract Amount (b)	7.5
Fair Value (b)	0.5

2012
Strike Price (a)	5.13
Contract Amount (b)	2.0
Fair Value (b)	0.2

(a)Weighted average, in dollars

(b)Millions of dollars

ITEM 4. CONTROLS AND PROCEDURES

As of March 31, 2011, 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, 2011, 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, 2011 that has materially affected or is reasonably likely to materially affect SCE&G’s internal control over financial reporting.

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.

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
May 3, 2011		James E. Swan, IV
		Controller
		(Principal accounting officer)

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 99.1 to Form 8-K filed April 26, 2011 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 3.01to Form 8-K filed February 23, 2009 and incorporated by reference herein)

3.06		X	By-Laws of SCE&G as revised and amended on February 22, 2001 (Filed as Exhibit 3.05 to Registration Statement No. 333-65460 and incorporated by reference herein)

10.01	X	X	Contract for AP1000 Fuel Fabrication and Related Services between Westinghouse Electric Company LLC and South Carolina Electric & Gas Company for V. C. Summer AP1000 Nuclear Plant Units 2 & 3, dated January 27, 2011 (portions of the exhibit have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended) (Filed herewith)

10.02*	X	X	Independent Contractor Agreement between SCANA Corporation and William B. Timmerman dated January 7, 2011 (Filed herewith)

31.01	X		Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)

31.02	X		Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)

31.03		X	Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)

31.04		X	Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)

32.01	X		Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)

32.02	X		Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)

32.03		X	Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)

32.04		X	Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)

101. INS**	X		XBRL Instance Document

101. SCH**	X		XBRL Taxonomy Extension Schema

101. CAL**	X		XBRL Taxonomy Extension Calculation Linkbase

	Applicable to Form 10-Q of
Exhibit No.	SCANA	SCE&G	Description

101. DEF**	X		XBRL Taxonomy Extension Definition Linkbase

101. LAB**	X		XBRL Taxonomy Extension Label Linkbase

101. PRE**	X		XBRL Taxonomy Extension Presentation Linkbase

* Management Contract or Compensatory Plan or Arrangement

** 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.

Positive
Negative
Uncertain
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Legalese
Litigous
Readability	H.S. freshman Avg

Dominion Energy South Carolina (SCG) 10-Q2011 Q1 Quarterly report

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